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ANNUAL REPORT 2000

FEDERAL ENERGY

REGULATORY COMMISSION
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FEDERAL ENERGY

REGULATORY COMMISSION

Avista’s Noxon Rapids is a 460-megawatt hydro facility located on the Clark Fork River in

northwestern Montana. It was built in 1959 and is 260 feet high.

Photo courtesy of Avista Corp.
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TABLE OF CONTENTS

Members of the Federal Energy Regulatory Commission

Letter from the Chairman

Overview

Energy Markets

Energy Projects

Hydroelectric Power Table

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5

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15

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MEMBERS OF THE FEDERAL

ENERGY REGULATORY COMMISSION

James J. Hoecker

Chairman

Linda K. Breathitt

Commissioner

Curt L. Hebert, Jr.

Commissioner

William L. Massey

Commissioner
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LETTER FROM THE CHAIRMAN

To the Senate and House of Representatives

I am pleased to submit to the Congress the Federal Energy Regulatory Commission’s annual report, covering the fiscal year from

October 1, 1999, through September 30, 2000.

This is the 80th report issued by the Commission and its predecessor, the Federal Power Commission. As an independent agency,

the Commission oversees key operating functions of the natural

gas, electric utility, hydroelectric power, and oil pipeline transportation industries.

For fiscal year 2000, Congress appropriated $174.95 million to

support Commission activities. Under the authority of the Omnibus Budget Reconciliation Act of 1986 and other laws, the Commission recovers all of its costs from regulated industries through

fees and annual charges. Revenues generated from these sources

completely offset congressional appropriations and therefore result in a net cost to the treasury of zero dollars. As a result, the

users and beneficiaries of the Commission’s services not the general taxpayers pay its operating costs.

The Commission remains dedicated to protecting the economic

welfare of American consumers of energy and to ensuring a

healthy, competitive, and efficient energy industry.

Respectfully,

James J. Hoecker

Chairman
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Transmission tower. Photo by Rick Giammaria and

courtesy of the Potomac Electric Power Company
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OVERVIEW

THE COMMISSION’S REGULATORY RESPONSIBILITIES

The Commission is a five-member independent regulatory agency, which succeeded to the regulatory

responsibilities of the Federal Power Commission in 1977. The Commission’s responsibilities include the

licensing of non-federal hydroelectric facilities, the certification of natural gas pipelines, regulating the rates

of natural gas pipelines and pipelines transporting crude oil and oil products, and regulating the rates and other

aspects of electric utility activities.

Hydropower is the oldest area of Commission jurisdiction. The Commission’s predecessor began federal

regulation of non-federal hydroelectric generation in 1920, authorizing the construction of projects in interstate commerce and overseeing their operation and safety. The Commission now regulates 2,000 dams that

generate over five percent of all electric power in the United States.

Since 1935, the Commission has regulated certain electric utility activities under the Federal Power Act

(FPA). Under FPA Sections 205 and 206, the Commission oversees the rates, terms and conditions of sales for

resale of electric energy and transmission service in interstate commerce by public utilities. The Commission

must ensure that those rates, terms and conditions are just and reasonable, and not unduly discriminatory or

preferential. Under FPA Section 203, the Commission reviews mergers and other asset transfers involving

public utilities. The utilities regulated under FPA sections 203, 205 and 206 are primarily investor-owned

utilities; government-owned utilities (such as the Tennessee Valley Authority [TVA], the federal power marketing agencies, and municipal utilities) and most cooperatively-owned utilities are not subject to the

Commission’s regulation, with certain exceptions.

The Commission may not regulate retail sales or local distribution of electricity. These are matters left to

the states by the FPA. Nor does the Commission have a role in authorizing the construction of new generation

facilities (other than non-federal hydroelectric facilities) or transmission facilities. These too are state or local

responsibilities.

The Commission’s role in the natural gas industry is largely defined by the Natural Gas Act of 1938

(NGA). Under the NGA, the Commission regulates the construction of new natural gas pipelines and related

facilities and oversees the rates, terms and conditions of sales for resale and transportation of natural gas in

interstate commerce. Pipeline siting and construction is authorized by the Commission if found to be required

by the public convenience and necessity. As with hydropower licensing, the Commission’s actions on pipeline

projects typically require consideration of factors under the National Environmental Policy Act (NEPA), the

Endangered Species Act, the Fish and Wildlife Coordination Act, the Coastal Zone Management Act and other

such legislation. The wellhead price of natural gas, which the Commission previously regulated, was gradually deregulated by Congress beginning with the Natural Gas Policy Act of 1978 (NGPA). All wellhead price

controls on natural gas ended on January 1, 1993. Regulation of retail sales and local distribution of natural

gas are matters left to the States.

Finally, the Interstate Commerce Act (ICA) gives the Commission jurisdiction over the rates, terms and

conditions of transportation services provided by interstate oil pipelines. The Commission has no authority

over the construction of new oil pipelines, or over other aspects of the industry such as production, refining or

wholesale or retail sales of oil.

NATURAL GAS MARKETS

Today, natural gas commodity markets are competitive. There is truly a continental natural gas market in

North America. Reserve prospects are very promising. However, production, transportation, and distribution

capabilities will be tested by the significant annual demand growth—from 21 trillion cubic feet (Tcf) today to

30-35 Tcf in 2015. A sizable portion of the increase will come from gas-fired electric generation. In the current

market, natural gas buyers are no longer limited to buying from one or two pipelines and instead have a wide
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OVERVIEW

range of supply options that can be reached through various pipeline transportation options, including capacity release or at market hubs. In addition, an active financial market has developed to allow buyers and sellers

of natural gas to hedge against future increases in natural gas prices.

This competition has produced substantial benefits for consumers. Retail gas prices, for example, declined by 42 percent in inflation-adjusted dollars from 1984 to 1994. If gas prices had remained at 1984 levels,

consumers would have paid $50-60 billion more for gas in 1995.

Spot wellhead prices for natural gas roughly doubled over the last year. The wellhead price averaged over

$4.00 per thousand cubic feet in the latter part of the fiscal year. (Energy Information Administration [EIA]

Short-Term Energy Outlook, September 2000.) However, transportation access made the commodity market

liquid and efficient and, despite recent price increases, consumers still saved money compared to pre-competitive prices. For example, according to one analysis of EIA data, wellhead prices have declined from $4.10/

MMBtu in 1983 to $3.13/MMBtu today, in 1998 inflation-adjusted dollars. Moreover, recent wellhead price

increases have already prompted a market response by producers to increase the supply of natural gas. The

number of natural gas drilling rigs in use, for example, more than doubled in the past 15 months.

The Commission will continue to assure that competitive pipeline transportation markets continue to

work in the public interest.

WHOLESALE POWER MARKETS

Bulk power markets are not as mature as natural gas markets. The transmission provisions of the Energy

Policy Act (EPAct) and the Commission’s Order No. 888 of 1996 have greatly expanded trading opportunities

in wholesale markets, and the Commission’s ongoing initiative on regional transmission organizations (RTOs)

should further address remaining transmission obstacles to competition. And, as sources of generation become more diverse, market power will further diminish in wholesale power markets.

However, circumstances this fiscal year demonstrated the still-developing nature of competition in bulk

power markets and the need for continuing vigilance by the Commission. Wholesale prices in California, for

example, increased significantly, at least for the summer peak months. Prices in some other parts of the country were also more volatile than in the past. In addition, retail consumers in some areas increasingly faced the

risk of brownouts or blackouts.

The most dramatic price increases were in California. According to San Diego Gas & Electric Company

(SDG&E), for example, wholesale market prices in June and July of 1999 rarely exceeded $150/megawatthour (MWh), while prices for the same period in 2000 exceeded $250/MWh in 167 hours and $500/MWh in

59 hours.

Recognizing the need for pro-active steps in California as well as other parts of the country, the Commission in late July directed its staff to investigate the conditions in bulk power markets throughout the country.

Staff was told to determine any technical or operational factors, regulatory prohibitions or rules (federal or

state), market or behavioral rules, or other factors affecting the competitive pricing of electric energy or the

reliability of service, and to report its findings to the Commission.

In July, SDG&E, which was flowing volatile wholesale power costs through to retail ratepayers, filed a

complaint with the Commission, seeking immediate imposition of a price cap of $250/MWh for all public

utility sellers in the California wholesale markets. On August 23, the Commission ruled on this complaint,

instituting formal hearing proceedings under FPA section 206 to investigate the justness and reasonableness of

the rates of public utility sellers in California. The Commission also investigated whether the tariffs, contracts,

institutional structures, and bylaws of the Independent System Operator (ISO) and Power Exchange (PX), new

market institutions created under California statute, were adversely affecting the efficient operation of competitive wholesale power markets in California and need to be modified. By establishing the hearing proceeding in the August 23 order, the Commission had the ability under the FPA to order refunds, as appropriate, if it
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OVERVIEW

found that rates for sales by public utilities to the ISO or the PX were unjust or unreasonable. The Commission

expected that its actions and the measures adopted by the state would moderate price volatility in California

markets.

Price volatility also increased in other parts of the country in the summer, particularly the Northeast. In

response, the Commission authorized temporary price caps in both New York and New England. These regions were another focal point for the investigation being conducted by the Commission’s staff.

Some of the market-specific issues that appeared to be affecting prices included:

u Construction of new generating facilities had not kept pace with rapidly rising electrical demand.

According to the California Energy Commission, from 1996 to 1999, demand for electricity in

California grew by 5,522 MW, but only 672 MW of new generating facilities were added.

u State-regulated wholesale buyers had been purchasing most of their power in spot markets,

which saw high prices, instead of purchasing power under long-term contracts or hedging their

purchases.

u Rates for most buyers were averaged over time (for example, a monthly bill based on total

electricity used during the month) so that customers had little incentive to reduce their usage

during peak hours when electricity costs are highest.

u There was little competition at the retail level by energy service providers. While many utilities

sell power in California’s wholesale markets, few compete to sell power directly to retail customers. As a result, those customers were offered few innovative pricing or service options.

u According to some observers, sellers in California engaged in collusion or other anticompetitive

behavior. These allegations were being investigated.

Based on the staff report to the Commission, at the end of the fiscal year, the Commission was preparing

to take further measures, as appropriate, to address these issues.

However, the FPA defines the boundaries of the Commission’s authority, and leaves responsibility for

many helpful measures with California (and other states). For example, the California Energy Commission is

responsible for authorizing the construction of new generation and transmission facilities in the state. The

state also decides whether state-regulated wholesale buyers are restricted to buying in spot markets or are

allowed to choose prudently among the full range of wholesale buying opportunities, including long-term

contracts and hedges.

LOOKING AHEAD

The Need to Adapt Regulation

Energy is the lifeblood of the American economy, which boasts an energy industry that is one of the best

and most cost-efficient in the world.

An efficient, reliable energy industry is essential both to the ongoing success of the American economy

and to the well-being of millions of Americans. Growing competition in electricity and natural gas markets

promises great benefits. However, natural gas and electricity both reach consumers through physically integrated transportation networks (pipelines for natural gas and transmission lines for electricity). Realizing the

full benefits of competition–a policy that is central to the Commission’s aim to build a power system for the

21st century–depends on:

u fair, open access to the transportation grids;

u appropriate regulation of the monopoly aspects of the grids; and

u strong commodity markets that reflect the limitations of the grids and operate both efficiently

and fairly.

The importance of the Commission’s work is evident in events over the past year. Energy prices have

become a major issue for most Americans, as shown by the breakdown of California’s electricity market and
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OVERVIEW

the rising price of natural gas. Reliable energy service is also critical, with headlines reporting blackouts in

San Francisco and Detroit. The Commission is deeply involved in responding to these events and must push

through with the steps needed to ensure properly functioning energy markets and infrastructure.

This changing context has major implications for how the Commission operates. If it is to sustain a

policy of encouraging competition for consumer benefit, the Commission must:

u become the watchdog of market integrity;

u be increasingly attuned to the effects of the transportation grids on the commodity markets and

vice versa; develop the capacity to act much more quickly than ever before; and

u continue adapting its regulation.

The Commission has succeeded for half a century using a command-and-control, cost-of-service model

as the basis for most of its regulation. For most of the last quarter century, it has adapted the basic cost-ofservice model to promote competition first in the natural gas industry and more recently in the electric industry. This underlying regulatory model–cost-of-service regulation that adapts to accommodate growing competition–has produced large benefits for American consumers. For a decade and a half, it helped foster relatively

low natural gas prices and the growth of a large independent power industry.

The model remains valid today. As traditional monopoly providers change or disappear, however, the

traditional focus on cost-of-service regulation is no longer adequate to ensure that energy prices in the wholesale markets the Commission regulates will always be just and reasonable. Recent experiences reveal that:

u market rules on bidding, congestion management, and other matters can have dramatic effects on

prices and require strong independent oversight;

u timing of investments, barriers to siting, and inflexible demand can lead to shortages and high

prices even in a well-structured market; and

u political pressure to roll back competitive reforms can arise rapidly and powerfully, so the need

for expedition in achieving market transformations is doubly important.

Energy projects–infrastructure–are critical to the success of energy markets. As our expanding economy

increases the thirst for energy, reliability concerns increase. This, in turn, makes prudent expansion of the

energy infrastructure a more visible part of the Commission’s mission. The Commission plays a direct role in

the development of interstate natural gas pipelines and nonfederal hydroelectric facilities.

Siting new natural gas pipeline facilities requires difficult decisions, sound processes, and expert staff

advice. Growing environmental awareness and citizen involvement in land use decisions make these projects

more controversial than ever before. At the same time, the needs of natural gas and electric markets heighten

the importance of siting new facilities quickly and pricing them appropriately. Reducing the time needed to

process filings for new facilities becomes increasingly important as market demands shift quickly for both

retail usage and new electric generation. This in turn presents new issues for determining market need and

granting eminent domain authority to pipeline sponsors.

The Commission also oversees nonfederal hydroelectric facilities, and this type of energy infrastructure

carries its own set of challenges. These include balancing competing interests for water use, recreation, cost

allocation, and calculating the public interest over long time periods. The diverse regional interests in the

relicensing of the New York Power Authority’s Niagara Project embody such issues. The Edwards Dam settlement in Maine, in which the dam was dismantled after 160 years, shows how balancing competing interests

and looking for consensus can result in support for taking a new direction.

For the next year, the three biggest challenges facing the Commission are:

u to respond well to changing markets, especially for electric power;

u to continue the high quality of its case work, while improving timeliness in key areas; and,

u to continue to reinvest in the Commission’s employees.
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OVERVIEW

Responding to Market Changes

The last year has made clear how difficult the electric industry’s transition to competition can be, how

important it is to complete the transition sooner rather than later and how important it is for the Commission

to respond to unforeseen developments quickly and effectively. For example:

u Specific aspects of market structure, such as bidding rules, can be vitally important. When

flawed, they must be remedied quickly.

u Market power still exists in the electric industry and can appear in new and unexpected ways.

The Commission must be able to recognize new exercises of market power and respond quickly.

u The financial health of the industry requires stable institutions so that capital markets can judge

risks and allocate capital reasonably. The transition to competition must not be prolonged.

u Both companies and regulators make mistakes in new situations leading to problems both for

individual players and the market as a whole. Again, the transition to stable markets and

regulatory approaches must be as short as possible.

The coming year will be a time of transition for the electric power industry. If that transition is to be

finished soon, it must to be a decisive time for the Commission. The Commission’s most important priority for

the next year is to develop its ability to understand market changes and to respond quickly and appropriately

when needed. Developing the Commission’s response capability will require interlocking initiatives:

First, the Commission must develop its Market Oversight and Assessment (MOA) function. Today, this

function is still in its formative stages. By the middle of next year, we must be able to understand unexpected

market developments, identify issues that need resolution, and propose options for solving the problems,

doing all of this in days rather than weeks. Building MOA is a Commission-wide priority.

Second, the Commission must be able to act quickly as markets develop in unforeseen ways. This will

mean being able to adopt innovative procedures and refocus resources rapidly when needed. The Commission

has already shown its ability to do this in its response to the Independence and Millennium pipeline certificate

cases and to the California electric markets. It will need to build on these experiences to fold public consultation into expeditious processes.

Third, the Commission and the states must work out an effective way to regulate the electric markets of

the future. For example, any retail open access program (regulated by the states) requires strong, competitive

wholesale markets (regulated by this Commission). Similarly, wholesale markets will often work well only if

electricity customers respond to changing prices. State and federal authorities are regulating a single, integrated industry, and must regulate it in a coordinated way.

The central goal: lower rates, improved service and more scope for competition.

VISION

Promoting Competitive Markets

Protecting Customers

Respecting the Environment

Serving and Safeguarding the Public

VALUES

Employees–People are our most valued asset. We provide the support needed for all employees to excel.

Integrity–We maintain the highest level of professionalism and an environment of fairness, trust, respect, and honesty.

Diversity–We value diversity in people and ideas.

Working Together–We clearly communicate expectations, encourage cooperation and teamwork, and share responsibility.

Progress and Innovation–We are creative and flexible, and seek out opportunities to improve.

Action–Prompt and fair resolution of matters before the Commission is essential to our mission.

Reaching Out–Two-way communication with the public is key to our effectiveness.

Public Service–Our ultimate objective is to provide valued services to the public.

FERC VISION AND VALUES STATEMENT
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OVERVIEW

FERC FIRST

During FY 2000, the Commission began to see the results of FERC First, its reengineering program

which was one of the most extensive in the federal government. To begin with, the Commission’s resources

were redistributed among three basic processes:

u energy markets, including both traditional and market-based regulation of the electric, natural

gas and oil pipeline industries;

u energy projects, including certification of natural gas pipeline facilities, hydropower licensing

and relicensing, and dam safety; and

u management, including information technology, human resources, budgeting, and facilities.

Much more has changed than office structure, however. The Commission is taking new approaches to its

work.

Teaming is a way to leverage our human resources to gain better results. It replaces multiple office-tooffice paper hand-offs with interdisciplinary coordination, staff empowerment, and less repetitive review.

Teaming ultimately knits all offices together at all levels of the organization.

Customer focus means the Commission seeks to meet people’s needs. Making good and timely decisions

is a real service to everyone involved in a case and to the public at large. The Commission’s customer focus

can entail outreach, which bridges gaps between the Commission and parties affected by the agency’s work, or

finding solutions to problems before they become contested cases, and increasing trust and information sharing, which leads to better outcomes.

Faster decision making helps the Commission respond to the pace of change in today’s energy industries.

Finding efficiencies in workload processing is also essential due to resource constraints and the need to put

available effort into the highest-priority areas.

Strategic thinking is now built into the way the Commission does business, organizationally and culturally. The Commission staff has long been accustomed to “fighting fires”–making short-term decisions about

itself or the industry. Because of the Government Performance and Results Act (GPRA) and FERC First, the

Commission now does things differently.

Reengineering has enabled the Commission to focus on understanding and monitoring energy markets,

improving energy infrastructure and offering new services to the Commission’s constituents.

At the same time, an Internet-based system for accepting and processing filings electronically and managing the growing workload through better use of information technologies has successfully augmented these

reforms. New electric filing procedures have been successfully tested and a steady phase-out of paper filings

is scheduled for the years ahead. A Manage-to-Budget system has made all Commission administrators most

cost-conscious in requesting and allocating resources.

Meantime, staff has been reduced about eight percent in the past three years and, all things being equal,

will be cut by an equivalent number over the next five years. FERC First will thereby save taxpayers some $35

million in salaries and benefits between now and 2005.

Even as this major reengineering was under way, the Commission cut its processing time in such key

areas as certification of natural gas pipelines, litigated cases, and merger clearances in its drive to provide

rapid and effective responses to industry and consumer needs.

The Commission regulates key interstate aspects of the electric power, natural gas, oil pipeline,

and hydroelectric industries. The Commission chooses regulatory approaches that foster

competitive markets whenever possible, assures access to reliable service at a reasonable price,

and gives full and fair consideration to environmental and community impacts in assessing the

public interest of energy projects.

FERC M ISSION S T A TEMEN T
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OVERVIEW

Authorization and

Monitoring of

Energy Facilities

- Siting

- Environmental

- Safety

No

No, except for programmatic

EISs for some major actions.

No

Yes. The Commission issues

certificates for construction of

pipelines and related facilities.

Yes, NEPA review and

interagency consultation for

pipelines to be certificated.

No, except as part of initial

certification–incorporation of

DOT standards.

No

No

No

Yes. The Commission issues

licenses, exemptions, and

license amendments.

Yes, NEPA review and

interagency consultation for

the above authorizations.

Yes, dam and public safety.

RELATED RESPONSIBILITIES OF OTHER KEY AGENCIES

States Retail sales, local distribution,

siting for transmission lines

and generation facilities,

unbundled retail transmission

Retail sales, local distribution,

intrastate transportation, natural

gas production and gathering

Siting Projects that do not affect

navigable waters, interstate

commerce, or Federal lands or

dams

Other Federal Agencies DOE: Power Marketing

Administrations

EPA: air quality

NRC: nuclear power licenses

USDA: electric cooperatives

DOT: safety

DOI: siting in offshore waters,

federal lands, national parks;

endangered species

USFS: siting in national forests

COE: water body crossings

Advisory Council on Historic

Preservation: cultural resources

EPA: PCBs

National Marine Fisheries Service:

offshore fisheries

DOT: safety DOI: federal lands, national

parks, fish and wildlife,

endangered species

USFS: national forests

Advisory Council on Historic

Preservation: cultural

resources

National Marine Fisheries

Service: Fisheries resources

KEY AREAS OF FERC REGULATORY RESPONSIBILITY

TYPE OF

REGULATION

INVESTOR-OWNED

ELECTRIC POWER

INTERSTATE NATURAL

GAS PIPELINES

INTERSTATE OIL

PIPELINES

NONFEDERAL

HYDROPOWER PROJECTS

Regulation of Markets

and Rates, Terms, and

Conditions of Energy

Services

- Transmission

- Sales for Resale

- Corporate

Yes

Yes

Yes

Yes

Yes

No

Yes

No

No

N/A

N/A

N/A
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DIVISION OF

CONGRESSIONAL,

INTERGOVERNMENTAL

AND PUBLIC AFFAIRS

DIVISION OF PRESS

SERVICES

OFFICE OF EXTERNAL

AFFAIRS

COMMISSIONER COMMISSIONER CHAIRMAN COMMISSIONER COMMISSIONER

OFFICE OF

ADMINISTRATIVE LAW

JUDGES

OFFICE OF THE SECRETARY

OFFICE OF

STRATEGIC DIRECTION

OFFICE OF THE CHIEF

INFORMATION OFFICER

DIVISION OF

PROCUREMENT

DIVISION OF

LOGISTICS

MANAGEMENT

OFFICE OF THE

EXECUTIVE DIRECTOR

DIVISION OF

FINANCIAL POLICY

DIVISION OF

BUDGET

DIVISION OF

FINANCIAL SERVICES

DIVISION OF HUMAN

RESOURCES

MANAGEMENT

2000 FERC ORGANIZATIONAL CHART

DIVISION OF

ORGANIZATIONAL

MANAGEMENT

DIVISION OF

MANAGEMENT

ADMINISTRATIVEAND

PAYROLL SUPPORT

DIVISION OF

REGULATORY

ACCOUNTING

POLICY

DIVISION OF

REGULATORY

AUDITS

FERC REGIONAL

OFFICES:ATLANTA,

PORTLAND, CHICAGO,

NEWYORK, AND SAN

FRANCISCO

DIVISION OF

ADMINISTRATION

MARKET OVERSIGHT

AND ENFORCEMENT

ENERGY PROJECTS

MARKETS, TARIFFS

AND RATES

DISPUTE RESOLUTION

SERVICE

SOLICITOR

OFFICE OF THE GENERAL

COUNSEL

OFFICE OF

HYDROPOWER

ADMINISTRATIONAND

COMPLIANCE

DIVISION OF

PIPELINE CERTIFICATES

DIVISION OF

ENVIRONMENTAL AND

ENGINEERING REVIEW

OFFICE OF

ENERGY PROJECTS

MANAGEMENT AND

OPERATIONS

DIVISION OF

DAM SAFETY AND

INSPECTIONS

OFFICE OF

ADMINISTRATIVE

LITIGATION

DIVISIONOF POLICY,

INNOVATION AND

COMMUNICATION

DIVISION OF

INFORMATION

TECHNOLOGY AND

ORGANIZATIONAL

MANAGEMENT

DIVISION OF ISSUE

IDENTIFICATIONAND

RESOLUTION

MANAGEMENT

CHIEF ECONOMIC

ADVISOR

OFFICE OF MARKETS,

TARIFFSAND RATES

DIVISION OF TARIFFS

AND RATES–WEST

DIVISION OF TARIFFS

AND RATES–CENTRAL

DIVISION OF TARIFFS

AND RATES–EAST

DIVISION OF

CORPORATE

APPLICATIONS

DIVISIONOF ENERGY

MARKETS

OVERVIEW
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ENERGY MARKETS

GOALS

The overall goal of the Commission’s Energy Markets Program is to maximize benefits to consumers and

suppliers of energy through open, fair and flexible regulation.

Competition is growing in the electric generation and marketing sectors and the natural gas sector, in response

to the EPAct and the efforts of the Commission to remove barriers to competition. Effective regulation of transmission facilities that are essential for delivering natural gas and electric power is critical to ensure that consumers

receive the appropriate benefits from competition in power markets. Likewise, effective restraints on the exercise of

market power in these newly competitive electricity and natural gas markets is essential to advancing competition.

The Commission has long promoted competition in the key markets it regulates–wholesale electric energy and

transmission, also natural gas transmission markets–to foster a more efficient energy industry and to bring energy

consumers reliable energy at the lowest reasonable cost. Our goal has been to rely on competition where competition can work and bring benefits to consumers in the long run. However, we continue to regulate rates and terms of

access for essential transmission services, to monitor the wholesale markets that we regulate and, where necessary,

to apply traditional or other appropriate regulation to curb market power and ensure consumer protection.

Over two decades ago, Congress and the Commission began to encourage the development of competition in

the natural gas industry and in the last decade in the electric industry. As a result of these efforts, today’s natural gas

commodity markets are competitive, producing substantial benefits for consumers. Although natural gas commodity prices have risen this year, the Commission believes that this is largely an appropriate price response to a

generally tighter balance between supply and demand.

Competition in the electric bulk power markets is not yet as developed as competition in natural gas markets.

Competitive wholesale electricity prices in California this summer have been particularly volatile. In response to the

volatile prices in California and other parts of the country that occurred this summer, the Commission directed its

staff to investigate the condition of bulk power markets and report its findings. In each energy industry, the Commission has fostered the emergence of competitive markets and now must address key market issues by formulating

new regulatory approaches. For example, the Commission encouraged market growth by separating operational

control of energy production from energy transportation. The Commission will continue to regulate transportation

with the goal towards ensuring competitive commodity markets. The Commission also mandated open access for

the transportation systems, thereby enabling any user of the system to buy the same level of service at the same cost

as the system owner would pay.

The Commission continues to encourage natural gas pipeline-specific proposals to implement new, innovative

services. The Commission considers pipeline filings for flexible services and negotiated rates to increase capacity

use and to meet individual customer needs. For example, the Commission authorized an hourly firm transportation

rate schedule, limited availability services for niche markets, and volumetric and seasonal rates. In particular, specialized tariff services are enabling natural gas pipelines to serve expanding electric generation markets. The Commission also will continue to authorize an expanding array of new services such as parking, lending, and market hub

services that meet the needs of customers.

The Commission anticipated the continued convergence of the electric and natural gas industries by integrating its electric and natural gas staffs and internal procedures. This realignment will enable the staff to increasingly

focus on whole energy markets rather than individual companies and increase efficiency and consistency.

This section discusses, by objective, the Commission’s key initiatives, strategies, and processes for reaching its

energy markets goal. Achievements during the last year appear at the end of this section.

The Commission’s objectives for energy markets are to:

u Increase pricing efficiency

u Nurture competitive market institutions

u Constrain market power

u Resolve disputes quickly and fairly.
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ENERGY MARKETS

ACHIEVEMENTS

Formed the Office Of Markets, Tariffs And Rates

The Office of Markets, Tariffs and Rates (OMTR) became fully operational on February 27, 2000. OMTR

combines the Office of Electric Power Regulation, the Office of Economic Policy, most of the Office of

Pipeline Regulation, and part of the Office of Finance, Accounting and Operations. OMTR was created to

integrate the Commission’s economic regulation of the electric, natural gas, and oil industries. OMTR deals

with matters involving markets, tariffs and rates relating to electric, natural gas pipeline, and oil pipeline

facilities and services. It will play the lead role in monitoring, promoting and maintaining competitive markets

and refining compliance auditing. As a result of the Commission’s reinvention effort (FERC First), the Commission is looking at how it can implement lighter handed regulation for energy transactions in competitive

markets. The Commission is also working to standardize terms and conditions for transactions that fall under

our jurisdiction. This office reflects the convergence of electric and natural gas concerns already taking place

in the energy industry.

Issued its State of the Markets Report

As a signal to the future approach to regulation, the Commission issued its “State of the Markets 2000”

report to Congress on April 4, 2000. This important new document underscores the Commission’s increasing

focus on the structure and operation of energy markets, as distinguished from the services provided by individual companies. In it, the Commission reports on how natural gas and electricity markets have evolved in the

past few years, in both regulated and unregulated sectors. Such baseline information will become increasingly

important in judging the beneficial effects of competition, assessing the success of Commission policies, and

focusing Commission oversight of the energy markets.

The State of the Markets report gives a better picture of the critical aspects of the energy system. It

describes the development of competitive commodity markets for electric power and natural gas as well as

broad changes in the operation of the interstate transportation networks for electricity, natural gas, and petroleum. It also explains how a series of rulemakings and major cases has helped these parts of the nation’s

energy system become more competitive. The “State of the Markets 2000” represents the Commission’s first

systematic effort to articulate an approach that will allow it to track the indicators of a well-functioning energy

market, such as efficiency, transparency, transactional liquidity, ease of entry and exit, and competition.

TIME STANDARDS FOR LITIGATED CASES

Case Type Hearing Reply Brief Initial Decision

Simple Case 19.5 weeks 25.5 weeks 29.5 weeks

Complex Case 32 weeks 40 weeks 47 weeks

Exceedingly Complex Case 42 weeks 53 weeks 63 weeks

Complaint 30 days 45 days 60 days

“Fast-Track” Complaint 3 days 5 days 8 days
17

ENERGY MARKETS

Industry Outreach

The Commission staff conducted 19 informal outreach meetings with trade associations and energy,

environmental, and consumer organizations to explore issues relating to visions of the future and the regulatory changes that would be required to meet those visions. The Commission also held a series of industry-wide

conferences on: (1) issues relating to state unbundling of natural gas services and how our current regulations

facilitate or hinder those efforts; (2) projected gas pipeline capacity demands for the northeastern portion of

the United States; and (3) issues relating to revisions to electronic filing requirements. In addition, the Commission held a number of conferences around the nation to facilitate implementation of Order No. 2000.

Conducted Alternative Dispute Resolution (ADR)

The vast majority of disputes sent to litigation were resolved through the negotiation and settlement process. This is the most cost effective and efficient means of resolution available to the parties, and was a point of

primary emphasis for the Commission’s litigation staff and administrative law judges. Indeed, a remarkable 80

percent of the cases set for litigation were either fully or partially settled. To maintain and enhance this record, the

Commission conducted extensive training for its staff in alternative dispute resolution techniques.

Developed Reduced Timelines in Cases Set for Hearing

When settlement is not possible or warranted, the Commission’s regulatory responsibilities demand the

expeditious development, consistent with the due process rights of the parties, of a full and complete record upon

which the Commission can base its decisions. To that end, during FY 2000 the Commission developed new

timelines for cases set for hearing before the Commission’s administrative law judges in order to speed the

processing. The timelines offer a predictable time frame and are likely to result in substantial time and cost

savings for our customers. The time required to litigate many cases will be reduced by an average of one fourth.

 Completed Completed

 October 1998-September 1999 October 1999-September 2000

 Days Days

 Category # of Dockets (average) # of Dockets (average)

NO PRECEDENTIAL 174 108 74 95

ISSUES, UNPROTESTED

NO PRECEDENTIAL 31 247 10 168

ISSUES, PROTESTED

PRECEDENTIAL ISSUES 39 300 42 210

MAJOR ENVIRONMENTAL 14 438 23* 437*

IMPACT

*Excludes the Independence Project

PROCESSING TIMES FOR NATURAL GAS CERTIFICATES
18

ENERGY MARKETS

Expedited Approval of Uncontested Settlements

The Commission instituted process improvements that will result in faster approval of uncontested settlements certified to the Commission by the administrative law judges. In the future, the information formerly

provided to the Commission by staff memorandum will be provided in the judge’s certification of settlement and

draft Commission letter order, thereby reducing Commission review time. Under this procedure, the Commission anticipates approval of the settlement within 45-60 days of certification. An added benefit from this procedure is the fact that all documents will now be public.

Receives First Completely Paperless Filing

On November 4, 1999, the Commission issued a Notice of Proposed Rulemaking, RM00-1-000. The Commission proposes to amend its regulations to provide for the electronic filing of FERC Form Nos. 423, 714, and

715. The program allows for electric utilities to file the forms electronically in lieu of submitting any paper. On

February 18, 2000, the Commission received the first completely electronic Form 423, through its Internet web

site. Form 423 provides monthly reports on the cost and quality of fuels for electric plants. This initiative will

expand to include other forms filed at the Commission. It is one more example of how the Commission is

utilizing available technology to the benefit of the industry and consumers.

Electronic Filing of Documents

On September 14, 2000, the Commission issued Order No. 619, which amended its rules of practice and

procedures (18 CFR Part 385) to permit the electronic filing of limited categories of documents in proceedings

before the Commission on a voluntary basis. This order permits parties to file comments via the Internet. However, it excludes comments on rulemakings and settlements, and those submitted in connection with matters set

for hearing. The Commission expects gradually to expand the categories of submissions that it will accept in

electronic form. This furthers the Commission’s goal of reducing the amount of paper that participants in Commission proceedings must file. Increased use of electronic filing will reduce the burden and expense associated

with paper filings, and help to make information available to the public in a faster and more efficient manner.

This final rule is effective on November 1, 2000.

ELECTRIC ISSUES

Mergers

Corporate consolidation and convergence continues to be among the strongest forces changing the electricity industry. The Commission recognizes the long-term opportunities these developments present for promoting open and competitive markets, delivering rate benefits for consumers, and encouraging new investments and infrastructure. Utility mergers can help generate enormous benefits, including innovative services

and better reliability. In recent years, this Commission has experienced an unprecedented increase in major

merger applications, including natural gas and electric utility combinations which raise very complex competition issues. The Commission has worked diligently to act promptly to complete its review of these mergers

within the time frame set out in its 1996 Merger Guidelines, as well as to ensure that competition and other

public interests are not adversely affected. Such corporate consolidation will tend to make the commercial and

operational perspectives of market participants truly regional in nature. The Commission has acted on 18

merger applications this year.

Merger Applications Acted On During FY 2000:

EC98-40-000 American Electric Power Company/Central and Southwest

EC99-81-000 Dominion Resources, Inc./Consolidated Natural Gas Company

EC99-99-000 Illinova Corp/Dynegy Inc.

EC99-101-000 Northern States Power Co. (Minnesota)/New Century Energies, Inc.
19

ENERGY MARKETS

EC99-106-000 Southern Indiana Gas and Electric Co./Indiana Gas Co.

EC99-109-000 Pennsylvania Enterprises/Southern Union Co.

EC00-1-000 Energy East Corp./CMP Group, Inc

EC00-026-000 Commonwealth Edison Co./PECO Energy Co.

EC00-027-000 UtiliCorp United, Inc./St. Joseph Light & Power Company

EC00-028-000 UtiliCorp United, Inc./Empire District Electric Co.

EC00-049-000 Consolidated Edison, Inc./Northeast Utilities

EC00-055-000 Florida Progress Corporation/CP&L Energy, Inc.

EC00-063-000 Sierra Pacific Power Company/Nevada Power Company/Portland General Electric

EC00-066-000 Consolidated Water Power Company/Stora Enso Oyj

EC00-067-000 PowerGen plc/LG&E Energy Corporation

EC00-070-000 Interstate Power Company/IES Utilities, Inc.

EC00-073-000 El Paso Energy Corporation/Coastal Corporation

EC00-075-000 NiSource Inc./Columbia Energy Group

EC00-076-000 Indeck Capital, Inc./Black Hills Corporation

The Commission has also experienced a marked increase in the number of corporate applications submitted pertaining to disposition of public utility property, consolidation or purchase of securities (Section 203

filings). Many of these applications involve the divestiture of transmission assets related to sale of generation

assets and corporate reorganizations. These ongoing changes in the electric industry are occurring in large part

as a result of continuing restructuring and the trend toward deregulation in the industry. With these changes,

and with Commission initiatives such as Order No. 2000, Section 203 corporate applications are expected to

remain an important part of the Commission’s regulatory mission.

RTO Order No. 2000

On December 20, 1999, the Commission issued a broad set of rules in Order No. 2000 calling on transmission-owning utilities to join RTOs. RTOs are key to providing a greater choice of service providers, greater

competition and lower prices for consumers through more efficient, reliable and non-discriminatory transmission systems. Order No. 2000 was the culmination of a lengthy process of conferences, consultations, and a

Notice of Proposed Rulemaking (NOPR).

The Commission’s objective in Order No. 2000 is for all transmission-owning entities in the nation,

including non-public utilities, to place their transmission facilities under the control of appropriate RTOs in a

timely manner. To that end, Order No. 2000 establishes minimum characteristics and functions for appropriate

RTOs and a collaborative process by which public utilities and non-public utilities that own, operate, or control interstate transmission facilities, in consultation with state officials as appropriate, will consider and

develop RTOs. It also lays out a proposal to consider transmission ratemaking reforms on a case-specific

basis; an opportunity for non-monetary regulatory benefits, such as deference in dispute resolution and streamlined filing and approval procedures; and a time line for public utilities to make appropriate filings with the

Commission to initiate operation of RTOs. As a result of this voluntary approach, the Commission expects

jurisdictional utility entities to form RTOs. To initiate the implementation of Order No. 2000, the Commission

hosted and facilitated industry discussion at five separate regional workshops around the country. A considerable amount of outreach and staff support for these regional collaborative efforts continues.

Streamlined Rate Schedule Sheet Designation Procedures for the Electric Industry

On March 31, 2000, the Commission issued a final rule (Order No. 614), amending its regulations to

require the inclusion of proposed designations for all rate schedule sheets that public utilities file with the
20

ENERGY MARKETS

Commission. The rule streamlines rate schedule sheet designation procedures for the Commission and the

electric industry. The rule will also conform public utility tariff filing procedures with those for interstate

natural gas and oil pipelines. This revision to the regulations accommodates the movement toward an integrated energy industry and facilitates the development of common standards for the electronic filing of all

electric, gas, and oil rate schedule sheets.

Bulk Power Investigation

On July 26, 2000, the Commission issued an order directing the Commission staff to undertake an investigation of electric bulk power markets. The purpose of the investigation is to allow the Commission to determine whether these markets are working efficiently. The staff report will determine if any technical or operational factors, federal or state regulatory prohibitions or rules, market or behavioral rules, or other factors are

affecting electricity reliability or the competitive pricing of electricity.

On August 23, 2000, the Commission ordered a formal Section 206 investigation of the electric rates and

structure of California’s ISO and PX as well as market-based sellers in the California market. The investigation comes in response, in part, to a complaint from SDG&E. Our goal in these proceedings is to detect and, to

the extent within our jurisdiction, to resolve as expeditiously as possible, any defects in the operation of

competitive power markets in California. To the extent market performance issues surface, in the investigation

or the Section 206 investigation, that concern the structure or independence of the ISO, the Commission will

also take up these issues to the extent they are present in any RTO proposal that is filed on January 16, 2001,

pursuant to Order No. 2000.

Orders Intended to Support Electric Reliability and Improve Congestion Management

The Commission issued Order No. 2000 to implement the framework for transmission reliability in

response to the North American Electric Reliability Council’s (NERC) initiatives such as: clarifications to

transaction curtailment procedures, market redispatch efforts to assist with congestion management, and facilitation of access to critical system information by system operators. The Commission also approved a tariff

filed by the East Central Area Reliability Council, a regional council of NERC, designed to improve reliability

by creating a settlement system that encourages proper system operation. The Commission took a series of

steps to support the industry’s efforts to ensure continued reliability during the summer’s high demand period

May through September, 2000.

Summer 2000 System Reliability

The Commission acted to aid the summer system reliability of the nation’s electric supply system. While

the law does not give it direct responsibility over these matters, Commission policies have always been directed toward ensuring the continued reliability of the electric power system as evidenced by the ongoing

collaborative efforts in the development of RTOs. The Commission took decisive action to support the reliability efforts of the electric industry in preparation for the summer of 2000. In a May 17, 2000, notice, the

Commission identified five actions intended to address short-term reliability through September 30, 2000,

including waiving certain filing requirements and offering to make Commission staff available to assist with

questions and suggestions related to reliability issues. Subsequently, on June 28, 2000, the Commission issued

a supplemental notice responding to comments received and clarifying its short-term actions.

Steps Taken to Aid Summer 2000 System Reliability:

u Adoption of streamlined regulatory procedures to facilitate businesses’ use of on-site generation

facilities to meet demand during peak use periods.

u Facilitate demand side arrangements by waiving prior notice requirements in order for utilities

and their customers to negotiate arrangements expeditiously to form an industrial generator.
21

ENERGY MARKETS

u Eliminate disincentives to demand side transactions by clarifying pricing formulas.

u Encourage utilities to reassess available transmission capacity.

u Have Commission staff answer inquiries on practical ideas about steps to support the electric

industry’s efforts with respect to reliability issues.

NATURAL GAS AND OIL

Policy Statement Providing Guidance for Pricing Pipeline Facilities Without Customer Subsidies

The Commission’s September 15, 1999, policy statement announced that a pipeline project that shows it

is financially viable without subsidies from existing customers is preferable to one that employs pricing that

rolls in the new costs to the pipelines’ existing rates. The new preference changes the Commission’s past

pricing policy, which had a presumption in favor of rolled-in pricing (allowing recovery of construction costs

from existing customers). The Commission will now favor incremental pricing in which construction costs are

recovered only from customers benefitting from the new project. The policy statement will allow the market to

decide whether a project is financially viable. In view of the new framework for analyzing pipeline certificate

applications, the Commission issued Order No. 615 on July 14, 2000, removing the optional certificate regulations.

Wellhead Determinations

The Commission issued a final rule, Order No. 616, on July 14, 2000, in Docket No. RM00-6-000,

reinstating wellhead determination procedures under Section 503 of the NGPA. The rule reinstates the procedures for Section 107 gas that qualifies for a tax credit under Section 29 of the Internal Revenue Code. The

regulations, which took effect on September 25, 2000, reinstate the determination procedures for coal seam

gas, Devonian shale gas, and tight formation gas produced through recompletions commenced after 1992 in

wells drilled after 1980 and before 1993, or through wells commenced after 1980 and before 1993. In addition,

the regulations provide that jurisdictional agencies may designate new tight formation areas.

Five-Year Review of Oil Pipeline Pricing Index

The Commission undertook a review of the effectiveness of the index used to measure actual cost changes

in the oil pipeline industry. This is the five-year review of the oil pricing index, established in Order No. 561,

issued October 22, 1993. It issued the findings in its Notice of Inquiry on July 27, 2000, on the adequacy of the

Producer Price Index (PPI) for Finished Goods minus one percent as an index to measure actual costs changes

in the oil industry. The oil pipeline carriers recommended PPI alone, and the oil pipeline shippers would like

a PPI with up to a two percent reduction. The Commission intends to conclude any further action by May

2001.

Order No. 637 - Changes in Gas Pipeline Regulation

The Commission made important changes to its regulatory framework and policies governing the interstate gas markets and transportation grid. The rapid development of the competitive markets for natural gas

presented challenges to the existing regulatory model. The Commission realized that its regulatory policy

must seek to reconcile the objective of fostering an efficient market that provides good alternatives to as many

shippers as possible with that of creating a regulatory framework that is fair and protects captive customers

without good alternatives. The rule provides new economic opportunities and improves efficiency within the

marketplace.

The Final Rule, Order No. 637:

u Temporarily removes price ceilings for certain short-term transactions

u Permits peak/off-peak and seasonal rates
22

ENERGY MARKETS

u Revises transaction procedures, such as scheduling

u Narrows the right of first refusal

u Improves reporting requirements to provide more transparent pricing information.

These changes are expected to create greater transactional liquidity and more competition. To ensure

they do, the Commission will obtain and make available better information about availability and price, enabling shippers to make more informed decisions. The implementation compliance process for this order will

continue into the next fiscal year.

Offshore Natural Gas Facilities Uniform Regulatory Regime

The Commission’s Order No. 639 approved an initiative designed to promote increased efficiency in the

marketplace by implementing a single set of regulatory requirements for virtually all offshore natural gas

transportation providers on the Outer Continental Shelf (OCS) (RM99-5-000).

The Commission uses its authority under the Outer Continental Shelf Lands Act (OCSLA) to require all

OCS pipeline facilities to render their transactions transparent by making available information regarding

their affiliations, rates, terms and conditions of service. This information will help the Commission and others

determine whether offshore transportation services adhere to the OCSLA which calls for open and nondiscriminatory access. The goal is to make previously inaccessible information about OCS transportation available to offshore producers and to the market generally. At times of high energy price volatility, we ensure

development of domestic natural gas supplies and mitigate any disproportionalities in regulatory treatment.

Deep-water exploration and development is critically important to our economy. The information will also

enable OCS shippers to make informed transportation arrangements and will allow the Commission, competitors, shippers and others to monitor OCS transactions for discriminatory or anti-competitive behavior.

Work crews lower a 36-inch gas pipeline into the ground near Mankato,

Minnesota. The pipeline, when completed, will transport

natural gas from British Columbia to Chicago.

Photo courtesy of Alliance Pipeline.
23

ENERGY PROJECTS

GOALS

The Commission’s goals for hydropower and natural gas pipeline projects are to:

u Foster a regulatory environment that facilitates the responsible development of transportation

capacity to meet potential increases in market demands for natural gas to 25 tcf in 2005 and 30

tcf in 2010;

u Optimize hydropower benefits by improving the environmental performance of hydropower

projects while preserving hydropower as an economically viable energy source; and

u Maintain and improve the safety of hydropower projects.

Responsible Development of Transportation Capacity

The Commission addresses multiple competing interests and timeliness issues concerning natural gas

certificates on an ongoing basis through its casework.

The pipeline industry is aggressively pursuing serving new markets for gas. In the new competitive

environment, pipelines are proposing to serve markets already served by other pipelines. Competing pipelines

and landowners who question the need for the new projects vigorously contest many of these proposals.

Processing these contested proposals requires significant resources.

Increasing availability of Canadian supplies, new deep-water production in the Gulf of Mexico, and the

growing market for natural gas in the Northeast will continue to result in large construction projects. The

Commission also expects that Canadian gas and oil suppliers will seek additional markets for their products in

the U.S., and that producers will explore options to export gas to Canadian and Mexican markets, which may

require pipeline construction. Pre-filing conferences and meetings are taking place to explore the utilization of

Alaskan gas reserves for the lower 48 states. Increased competition in markets and customers’ desires for

multiple, competing sources of supply will generate more NGA Section 3 filings and related requests for

Presidential permits for importing and exporting gas and oil. The Commission will also continue to see projects

related to the extensive exploration effort on the offshore outer continental shelf and construction of pipelines

to reach significant new gas supplies.

Growing demand in all regions of the country will continue to lead to applications for major pipeline

extensions and new pipelines to serve these regions. Meeting construction and service time frames will require

balancing the need for energy versus the impacts on landowners, communities, and customers of existing

pipelines and competing pipelines. Processing of major construction projects will entail technical conferences

and public meetings for environmental scoping and comments on draft documents, as well as the analysis of

data responses, comments, protests, and other filings.

The Commission also expects to continue to receive applications for storage development for peaking

capacity and supply flexibility, since customers will continue to be responsible for their own gas supply acquisition. Anticipated storage facilities include depleted gas fields, new leached-salt caverns, and liquefied natural gas (LNG) tanks. Commission review and approval of these projects, many of which will be located near

market areas, is likely to generate significant public interest regarding competition, need, and environmental

impact. Additionally, as storage fields age, more applications are expected for new wells and additional acreage for buffer zones.

The replacement and upgrading of pipeline facilities is also an area in which the Commission expects an

increase. The Commission anticipates many replacement facilities because of the aging of the national pipeline grid. Replacing aging facilities is necessary for safe pipeline operations. A replacement project may be

straightforward, with the pipeline proposing to merely remove old pipe and replace it with new pipe of the

same diameter in the old right-of-way. Replacement projects can become much more difficult if the pipeline

proposes to replace the old pipe with new pipe of a larger diameter, or to leave the old pipe in place, seal it off,

and install new parallel pipe.
24

ENERGY PROJECTS

Optimization of Hydropower Benefits

Electricity generated from the power of falling water is economic, renewable, available for peak demand,

and without emissions–a valuable contribution to, and a significant component of, the nation’s energy mix.

But because hydropower projects use and affect a variety of important natural resources, they must adjust to

increasing concern for the environment and shared jurisdictional authorities, while competing in rapidly changing

energy markets.

The public’s and congressional concern about the environmental impacts of hydropower operations continues to increase. This heightened concern, reflected in a host of environmental laws, results in many additional requirements in new licenses.

While the Commission’s responsibility under the FPA is to strike a balance among the many competing

power and nonpower interests, various statutory requirements give other agencies a powerful role in the licensing of projects. The Commission must share its licensing conditioning authority with numerous state and

federal agencies. Shared jurisdiction poses unique challenges to the Commission in issuing timely and balanced licenses.

Over the next 10 years, more than 220 project licenses will expire. Many of these projects significantly

affect regionally important environmental resources, and as such, have a high potential for conflicts. The

Commission mitigates this potential by: (1) having every integral stakeholder in the relicensing process (local

citizen groups, power users, Native Americans, environmental organizations, fish and wildlife agencies, and

the hydropower companies) at the table early in the process; and (2) having better communication among

agencies. Through this participation in early collaborative processes, the Commission’s authorizations address the needs of the stakeholders affected by the hydropower facilities.

Hydropower Project Safety

The Commission’s internationally recognized dam safety program ensures that the dams under its jurisdiction are properly constructed, operated and maintained. Because of the increasing number of older dams under

the Commission’s jurisdiction, continued vigilance is particularly necessary. As engineering technology, tools,

and procedures improve, the Commission conscientiously facilitates sharing of knowledge, and it works with

licensees, the engineering community, and federal and state agencies to maintain its outstanding dam safety

record.

Cabinet Gorge hydro facility, built

in 1952, is located in northern Idaho

and western Montana on the Clark

Fork River. Its generating capacity

is 220 megawatts. It is 208 feet high

and has four generating units.

Photo courtesy of Avista Corp.
25

ENERGY PROJECTS

ACHIEVEMENTS

Natural Gas Pipelines

The Certificate Policy Statement, approved by the Commission in September 1999, sets forth the steps

the Commission will use to balance the public benefits against the potential adverse consequences of an

application for new pipeline construction. The Commission will approve an application for a certificate only if

the public benefits from the project outweigh any adverse effects. Under this policy, pipelines are encouraged

to submit applications designed to avoid or minimize adverse effects on relevant interests including effects on

existing customers of the applicant, existing pipelines serving the market and their captive customers, and

affected landowners and communities.

Key to this policy is the preference of incremental pricing in which construction costs are recovered only

from customers that benefit from the new project. A threshold

requirement for approval, that project sponsors must be prepared

to develop the project without relying on subsidization by the

sponsor’s existing customers, protects all of the relevant interests. The Commission has certificated 39 projects under this policy,

all in fiscal year 2000.

Certification of Major Facilities Construction

The Commission authorized major projects that will expand

the capacity of the natural gas infrastructure in the Northeast,

Midwest, Southeast, and Western regions of the U.S.

The Commission issued certificates to Independence Pipeline Company, ANR Pipeline Company, and Transcontinental Gas

Pipe Line Corporation for the Independence Project. As authorized, the Independence Project will construct 625 miles of pipeline and 137,400 horsepower of compression at an estimated cost

of over $1.3 billion in order transport up to 916 Mmcf per day.

The Independence Project will provide natural gas service from

the Chicago area to markets in Pennsylvania, New York, and New

Jersey as well as other parts of the Northeast through interconnecting pipelines. Also in the Northeast, the Commission certificated Tennessee Gas Pipeline Company’s Eastern Express 2000

Project. This project is designed to deliver 173 Mmcf per day to

electric generation customers in Connecticut and Massachusetts.

The Commission granted a certificate of public convenience

and necessity to ANR Pipeline Company to expand its system in

Wisconsin. This system expansion will allow the delivery of an

additional 194 Mmcf per day to the Wisconsin market.

The Commission issued a certificate to Northern Border Pipeline Company to extend its system from its current terminus near

Chicago to northern Indiana. This will allow the Indiana market

to have access to Canadian gas supplies.

Transcontinental Gas Pipe Line Corporation was issued a

certificate to expand its system in Alabama and Georgia in order

to serve customers in those two states. Florida Gas Transmission

Company received authorization for its Phase IV Expansion in

TOTAL CUMULATIVE

MILES APPROVED

PIPELINE CONSTRUCTION PROJECTS

0

2000

1995

1996

5000 1997

1998

4000

3000

1000

1999

6000

7000

8000

9000

SOURCE: CERTRACK

10000

2000
26

ENERGY PROJECTS

Florida. Also in the South, the Commission certificated a new pipeline, Trans-Union Interstate Pipeline, L.P.,

to serve a large electric generator in Arkansas.

The Commission issued a certificate to a new pipeline company, Questar Southern Trails Pipeline, that

will convert an oil pipeline to gas service and construct other facilities. This pipeline will extend from Utah to

Long Beach, California. Wyoming Interstate Company received Commission authorization to expand its Medicine Bow Lateral in Wyoming and Colorado.

In total, the certificates issued to the major projects described above approved the construction of 1,710

miles of pipeline and 301,816 horsepower of compression to provide almost 4.4 Bcf per day of new capacity

at an estimated cost of about $2.2 billion.

In addition to the above authorizations, the Commission also made preliminary determinations on nonenvironmental issues on several major projects. Preliminary determinations were made on two new pipelines

in the Midwest, Horizon Pipeline Company and Guardian Pipeline, L.L.C., as well as two new pipelines that

would traverse the Gulf of Mexico from the Mobile Bay area to Florida, Gulfstream Natural Gas System and

Buccaneer Gas Pipeline Company, L.L.C. In addition, preliminary determinations were made on an expansion

of Tennessee Gas Pipeline Company’s system in the Northeast U.S. and an expansion of Transcontinental Gas

Pipe Line Corporation’s system in the Southeast U.S. These projects propose to construct over 1,600 miles of

pipeline and over 270,000 horsepower of compression to provide a total capacity of 3.5 Bcf per day at an

estimated cost of almost $3.6 billion.

The Commission issued certificates for the expansion, establishment of storage boundaries, or modification of wells and facilities for storage fields of Petal Gas Storage Company, Honeoye Storage Corporation,

Texas Gas Transmission Corporation, and Dominion Transmission, Inc. In addition, the Commission issued

certificates to add new facilities to the existing liquefied natural gas facilities of Southern LNG Inc. and

Distrigas of Massachusetts Corporation.

Initiative for Offshore Facilities

In 2000, the Commission issued a final rule under the OCSLA and also acted on a court remand of the

Sea Robin Pipeline Company case involving the Commission’s offshore jurisdiction. The rule establishes a

more light-handed regulatory approach for the transportation of natural gas on the outer continental shelf

which seeks to equalize competition and balance the interests of the marketplace and consuming public. The

light-handed reporting requirements under the rule apply to virtually all transporters in the outer continental

shelf (with certain limited exceptions). The reports will permit shippers in the offshore to obtain information

about the terms and conditions under which offshore transporters provide service. The Commission’s Sea

Robin decision clarifies and refines the test the Commission uses to determine whether facilities in the outer

continental shelf are jurisdictional. The decision recognizes the competitive dynamics in the offshore area and

eliminates the burden of federal regulation for facilities which are found to perform a gathering function.

Outreach

The Commission has begun an extensive outreach program with pipeline companies, federal, state, and

local agencies, landowners, and other interested parties. As a result of the outreach program, the Commission

expects: (1) to receive more complete and less contentious applications as more issues are resolved before

filing; and (2) to develop a toolbox of best practices for pipeline applicants. Both likely will reduce case

processing times. This natural gas program borrows from the success of the hydropower program’s process for

pre-filing collaboration and other outreach initiatives.
27

ENERGY PROJECTS

Sharing Resources

The common thread woven through energy projects is the NEPA process. Combining the environmental

and engineering professionals from the hydropower and natural gas staffs has created a broader and deeper pool

of technical expertise for both programs to draw on. For example, the hydropower program has developed considerable expertise in the use of Geographic Information Systems (GIS) to expedite the processing of certain

permits. This expertise is now focused on developing systems to use GIS to expedite the processing of proposals

to build new natural gas pipelines. Combining the two staffs has increased the ability of the Commission to easily

shift resources to meet changing caseloads in the pipeline and hydropower fields. To that end, some staff are

being cross-trained in the NEPA process for both industries.

HYDROPOWER

Increased Collaborative Efforts

The collaborative process encourages agreement and settlement of major environmental issues by facilitating greater participation, communication, and cooperation. The Commission will promote collaborative

efforts by encouraging participation in the Alternative Licensing Process (ALP) and several other efforts. The

ALP is a voluntary process designed to improve communication among interested parties, and allows the

Commission’s staff to provide requested assistance to participants early in the licensing process. The process

is flexible and tailored to the facts and circumstances of the particular project. Other efforts to promote collaboration include interagency hydropower workshops, stakeholder consultation meetings, and outreach efforts.

Resource Standards and

Adaptive Management

Provisions

With the resource standards approach (performance-based measures), the

Commission imposes the

desired result and allows the

licensee to decide the best

way to achieve that result.

Under the adaptive management approach, the Commission issues licenses with

terms that allow the Commission to react to changes

over time. The joint use of

resource standards and adaptive management provides a

more flexible approach, allowing stakeholders cooperatively to decide the best

and most cost-effective way

to meet license objectives.

The Commission has already initiated the use of

2000

20012002

20032004

2005

2006

20072008

2009

2010

1000

2000

3000

4000

5000

6000

7000

0

TOTAL MEGAWATTS AT HYDRO

PROJECTS UP FOR RELICENSING

FISCAL YEAR

*Fiscal Year 2000 is actual megawatts filed

M

E

G

A

W

A

T

T

S
28

ENERGY PROJECTS

these approaches in recent relicensing orders. During relicensing proceedings, Commission staff will examine

license objectives to decide how optimally to apply the resource standards and adaptive management approaches. In addition, Commission staff will institute monitoring procedures to learn how successful these

approaches are.

Settlements

Using the alternative licensing procedures and a collaborative approach, Avista Corporation prepared and

filed an application to relicense the existing Cabinet Gorge (P-2058) and Noxon Rapids (P-2075) projects in

February 1999. These projects abut one another on the Clark Fork River in Sanders County in northwest

Montana and Bonner County in northern Idaho and have a combined generating capacity of 697 MW. In

February 2000, the Commission issued a license for these projects requiring Avista to implement a comprehensive settlement agreement that was developed as part of the collaborative process and signed by 27 parties,

including all significant agencies and non-governmental organizations involved in the proceeding.

Two additional comprehensive settlement agreements were also filed on longstanding relicensings in

California. On July 28, 2000, Pacific Gas and Electric Company (PG&E) filed a settlement agreement on

behalf of itself and 9 federal and state agencies and non-governmental organizations to resolve issues associated with the 28-year relicensing proceeding for its Mokelumne Hydroelectric Project, FERC No. 137. The

settlement agreement is the result of over a year of discussions facilitated by FERC staff. On September 29,

2000, PG&E filed another settlement agreement on behalf of itself and 12 federal and state agencies and nongovernmental organizations to resolve issues associated with the 21-year relicensing proceeding for its Rock

Creek-Cresta Hydroelectric Project, FERC No. 1962. The settlement agreement is the result of two years of

discussions facilitated by FERC staff, and involves the use of resource standards and adaptive management

provisions as described above.

Capacity Development at Relicensing

When applicants use the ALP for relicensing, the Commission’s staff will promote examining the viability of installing additional capacity at the project site. The examinations will include such factors as streamflow

records, turbine hydraulic capacity, potential to improve generating efficiency, regional need for power, and

ways to avoid adverse impacts on environmental resources and economics.

Interagency Cooperation

A major issue for the hydropower program has been the need to coordinate the related work of several

agencies. The Commission took the lead in developing an interagency task force to improve the hydropower

licensing process.

In May 2000, the Commission and the Departments of Interior, Commerce, and Agriculture signed a

statement of commitment to make the hydropower licensing process more efficient and effective. A Joint

Settlement of Commitment outlines the administrative reforms developed by an Interagency Task Force that

these agencies created to improve the hydropower licencing process. The measures developed by the Task

Force will make the licensing process more timely and less costly by encouraging collaborative efforts and

settlements, improving communication among all participants and coordinating and streamlining the

Commission’s and other agencies’ processes.

This task force has recently achieved several goals, including agreements on noticing procedures and

NEPA processes. Guidance, including Collaborative Process Guidelines, a Primer on Writing Trackable and

Enforceable License Conditions, a report on improving the process by which studies are identified and conducted, and a report on improving coordination of Commission licensing with Endangered Species Act consultation are on schedule for completion.
29

ENERGY PROJECTS

Preliminary Permits

During FY2000, the Commission completed 60 applications for preliminary permits. These applications

are for projects at Army Corps of Engineers or other existing lock and dams and employ new design technology.

The new design involves a faster, cheaper, more environmentally friendly method for installing turbine

generators at existing dams. Instead of the conventional design, where the turbine generator is inside the dam

or powerhouse, this design installs a turbine unit externally, on the face of an existing dam or on a slab built on

a river bank next to the discharge area. Using siphons and existing gates and water conduits keeps costs down

by minimizing disruption to land and water resources. Installation can take less than eight weeks and construction can be as little as one half of the cost of conventionally designed facilities.

License Surrenders

Licensees and exemptees may decide to surrender their hydropower authorizations because a project is

no longer economical or because natural catastrophes have damaged or destroyed project facilities. To protect

the environment and the public, a license or exemption may be surrendered only upon agreement between the

licensee or exemptee and the Commission. In recent years, the surrender review process has become more

complex, with a corresponding increase in staff involvement, because of increased sensitivity to the environmental implications of ending Commission jurisdiction.

If construction of a licensed project has commenced, the Commission consults resource agencies that

provided the original terms and conditions. It seeks input from the public to ensure that local environmental

issues are considered in the surrender proceeding. It also prepares an environmental assessment of any need

for restoration for public safety and environmental integrity. These measures may range from simply locking

a perimeter gate to removing a dam.

License Transfers

Electric restructuring is prompting many licensees to reevaluate their

generating assets. As a result, the

Commission is receiving more applications to transfer hydropower project

licenses. For example, in FY 2000

PG&E announced a settlement agreement with consumer groups that, subject to approval by California and the

Commission, would supersede plans

to auction 68 hydro plants to third parties and result in applications for the

transfer of its hydropower licenses to

a non-regulated affiliate. Before approving a transfer, the Commission reviews the proposed transferee’s eligibility and considers potential compliance problems. The Commission also

works with transferees to ensure they

understand their responsibilities under

the license.

BETWEEN THE YEARS 2000

AND 2010, MORE THAN

220 PROJECT LICENSES

WILL EXPIRE. THESE

PROJECTS REPRESENT

ABOUT 22 GIGAWATTS, OR

37%, OF THE TOTAL

GENERATING CAPACITY OF

ALL LICENSED PROJECTS.
30

ENERGY PROJECTS

Land Use Issues

Amendment proposals requesting authorization for commercial development create opportunities for the

public to enjoy these reservoirs and enhance local economics. They also present challenges for the Commission to provide for a reasonable balance between developmental interests and wildlife and fishery values of the

water resources.

One way to reach this balance is to develop shoreline management plans that consider both economic and

environmental resource values. The Commission encourages licensees and, in some circumstances, requires

them, to develop shoreline management plans, in cooperation with resource agencies, property owners, local

governments, and other interested entities. Licensees typically revise these plans periodically, with the

Commission’s approval, to accommodate changes to environmental and economic circumstances.

Compliance with Authorizations

The Commission’s post-licensing compliance program includes monitoring, compliance assistance, and

penalty assessment under Section 31 of the FPA. The compliance program ensures that licensees observe the

terms and conditions of licenses, which are designed to protect and enhance the environment and provide

benefits to the public.

Post-Licensing Monitoring

Most licenses issued today require post-licensing monitoring. Monitoring the hydropower project provides data on the performance of mitigative measures, such as fish passage facilities, fishery habitat improvements, wildlife benefits, recreational enhancements, and cultural resource protection. It ensures that the measures are implemented, and also determines whether the measures are sufficient for the level of environmental

benefits envisioned at the time of licensing. New licenses frequently incorporate performance measures. These

licenses identify goals for environmental resource protection or enhancement and create a mechanism for

measuring whether the goal is achieved.

Cooperative procedures have been helpful in achieving post-licensing monitoring objectives. More performance-based conditions are being developed through the collaborative licensing efforts, as parties to the

licensing process recognize the importance and necessity of their role to fine-tune environmental conditions

and ensure their success.

The Commission will continue to help licensees meet their post-licensing monitoring obligations in

partnership with other agencies and participants. Early efforts focused on helping project owners with small

projects or recently issued licenses and exemptions.

Civil Penalties

The primary goal of the civil penalty program is to achieve compliance with the terms and conditions in

each license, exemption, or permit that protects and enhances environmental resources. The Commission

offers technical guidance and support, including several outreach programs. In addition, technical staff meets

with industry members and other interested parties to forge solutions to new or complex compliance issues. If

all else fails, however, the Commission may initiate a civil penalty proceeding, either to obtain compliance or

to penalize for violations having serious public safety or environmental implications. For example, in FY 2000

a licensee paid a civil penalty of $10,000 for its failure to take reasonable measures to prevent soil erosion on

lands adjacent to streams when a flow-line ruptured after it was left unattended with an inoperable leak detection system resulting in debris filling and temporarily blocking the flow of a creek. The Commission also

imposed a civil penalty of $15,000 for a licensee’s failure to install gauging and recording devices to monitor

stream-flow and pool levels. In another case, an exemption-holder agreed to pay $10,000 for failing to comply

with the Commission’s safety regulations and a compliance order directing the filing of an independent

consultant’s report and revisions to its emergency action plan.
31

ENERGY PROJECTS

Outreach

The Commission now makes outreach a part of its day-to-day operations as well as major policy initiatives. For example, in December 1999, Commission staff met with Georgia Power Company’s Land Department and its team of lake managers near Atlanta. During the workshop, Georgia Power Company described

shoreline management practices on its licensed projects and explained the numerous issues that confront them

each day in managing the shorelines for a variety of competing uses. Commission staff was able to offer

advice on shoreline issues using its experience with related issues for other projects.

At the 2000 International Boating and Water Safety Summit in April 2000, staff spoke on land and water

uses related to development along project shorelines at licensed projects, shoreline management and preparation of related applications. Similarly, in an effort to create a forum for licensees and Commission staff to meet

and discuss such issues, the Commission hosted a workshop in Charleston, S.C., in July 2000, which was

enthusiastically embraced.

Also in April, the Commission participated in an outreach effort concerning water-borne debris on the

lower Susquehanna River. The Susquehanna River system becomes heavily laden with debris during highflow periods, resulting in substantial project operating costs and significant impacts on local downstream

interests. The purpose of the outreach was to review the debris management measures taken at the Conowingo

Hydroelectric Project in response to a recent high-flow event on the river. The outcomes of the meeting were

the identification of: (1) further immediate actions to be taken by the project licensee in response to this event;

and (2) possible next steps, in cooperation with the Susquehanna River Basin Commission, toward the overall

improvement of debris management on the lower river. The Commission’s interests in attending were to: (1)

confirm that the project licensees are taking all reasonable and practical measures within their control in

handling these situations; and (2) offer appropriate advice and assistance, consistent with our regulatory role

and responsibilities.

In June 2000, staff traveled to Minnesota to resolve difficulties certain licensees were having developing

cultural resources management plans (CRMP) which can readily be integrated into the day-to-day operations

of their projects. Staff explained the various components of a hydropower license, discussed how the implementation of each requirement might affect cultural resources and the obligations under their Programmatic

Agreement the licensees needed to comply with. The session resulted in the group beginning to develop a

matrix to tie together all the requirements of each license and the day-to-day operations and maintenance of

their projects and the integration of the CRMP into their respective organizations.

In August 2000, staff met at the Smith Mountain Lake Project regarding shoreline management and

development. U.S. Congressman Virgil Goode, government representatives from the three adjoining counties,

and several commercial developers attended the meeting. At the end of the meeting, the participants had a

much better understanding of FERC’s obligations under the FPA, FERC’s efforts to expedite its approval

process, their responsibility to foster consensus decision making and more open communication among the

local stakeholders. The participants asked, and staff agreed, to attend possible future meetings with them when

they begin to develop a comprehensive management plan.

Shoreline Management Guidance Handbook

The Commission has begun the preparation of a shoreline management guidance book. In recent years,

the FERC has seen an increasing number of applications filed for shoreline development activities (specifically for non-project uses and occupancies of project lands and waters). Many of these applications have

drawn the interest of stakeholders who have filed letters concerning the effects of the proposed development

on project environmental resources. In many instances the Commission finds that the licensed project reservoirs help support an economically viable industry of waterfront housing and recreational boating. At some

projects, this industry is seasonal with second home and vacation rental properties located adjacent to project
32

ENERGY PROJECTS

land. At other projects there are increasingly more year-round, upscale homes, planned communities and

retirement homes. Organized homeowner associations are participating more frequently in public review and

comment processes for these proposals.

In response to this development trend, the Commission’s staff has been actively searching for ways to

work with our licensees and the concerned stakeholders to equitably balance the use of project land and water.

The Commission hopes to minimize the environmental effects of these uses of project resources while continuing to allow for public enjoyment of project resources.

The Commission recognized the need for a guidance document that discusses the Commission’s legal

authorities and regulatory role with regard to shoreline management, planning and monitoring.

Compliance Plans

Licenses issued today include conditions that will protect and enhance environmental resources. These

conditions result in the preparation by the licensees of plans or reports filed as compliance plans with the

Commission. These plans and reports may deal with project operation, development of recreational resources,

improvements to fishery habitat, water quality protection, wildlife benefits, wetlands and vegetation improvements, and cultural resources protection. Prepared after the license is issued, the plans and reports are typically developed by the licensees in consultation with identified agencies and groups, and are filed as applications with the Commission, frequently for Commission approval. In FY 2000, the Commission approved over

800 applications for plans and reports related to environmental requirements, addressing conditions that provide protection and enhancement of environmental resources.

Environmental Compliance Reviews

To ensure that licensees comply with the terms and conditions of its license, the Commission will continue to aggressively pursue reported incidences of environmental non-compliance. The Commission directs

the licensee to explain the circumstances surrounding the incident and, if necessary, provide additional information. In FY 2000, the Commission completed the review of over 200 investigations into allegations of noncompliance with environmental requirements. The Commission continues to develop cooperative relationships with resource agencies and local organizations to help resolve the issues raised by these allegations and

to ensure compliance with the conditions included in the issued licenses.

Environmental Review of Amendments

Protection of the environment remains a top consideration in the processing of license amendments. Under

NEPA, the Commission will continue to perform required environmental analysis of all changes to hydropower

licenses. The purpose of this analysis is to avoid or mitigate adverse effects on water quality, vegetation, wildlife,

historic and cultural resources, soils and geologic resources, land use, and air and noise quality. The Commission

conducts a thorough analysis of each of these areas before a license amendment can be issued.

Effectiveness of Environmental Measures

The Commission will track the outcome of environmental measures required at certain projects to decide

whether the Commission’s environmental policies are yielding the desired results and to monitor the need for

particular measures. The Commission will conduct investigations and discussions with licensees, stakeholders, and other interested parties to gather information. The Commission will use this information to decide

ways to improve the effectiveness of environmental mitigation measures. Through outreach meetings and

workshops, the Commission will distribute information for licensees and potential licensees in developing

their environmental resource protection plans. Outreach meetings and workshops will address such topics as

shoreline management programs, water quality protection, fish passage, and recreation management plans.
33

ENERGY PROJECTS

Unexpected Contingencies

Throughout a license term, events can occur that require immediate Commission action to resolve environmental problems. These events may be construction problems resulting in fish kills, dam repairs resulting in

environmental problems, or project operation endangering recently listed threatened and endangered species.

With the continuing listing of new endangered species, the Commission must implement habitat conservation measures to protect affected environmental resources. For example, in FY 2000, Commission staff issued

habitat protection plans for whooping cranes, least terns, piping plover, Karner blue butterflies, and waterfowl.

Recreational Fishing

As a member of the National Recreational Fisheries Coordination Council, the Commission developed

an annual report on actions and activities related to recreational fishing opportunities at licensed projects for

FY 1999. This report was provided to the co-chairs of the National Recreational Fisheries Coordination Council in March 2000. In FY 2000, the Commission approved or amended over 15 recreation plans, many of

which included provisions to enhance recreational fishing. Further, the Commission provided for recreation

and fisheries-related training for approximately 15 staff and also participated in the annual International Boating and Water Safety Summit and Waterpower Conferences. The Commission continues to provide and maintain a “Fishing Net” link on the Commission’s webpage.

Headwater Benefits

Section 10(f) of the FPA directs that the owners of non-federal hydropower projects who receive energy

benefits from upstream federal storage reservoirs must reimburse the upstream project owners for part of their

capital costs. The Commission conducts river basin studies and determines the assessments, which are returned to the U.S. Treasury. Approximately $6 million is collected annually for benefits received from 116

federal headwater projects throughout the country.

Federal Lands

When federal lands are reserved for waterpower purposes, the Commission must review any applications

for other uses of those lands. Other uses may include mining claims, oil and gas leases, mineral leases, rightsof-way and revocations under the FPA. The review allows the Commission and the Bureau of Land Management to protect existing licensed projects from adverse impacts from outside parties. It also allows for federal

lands not affected by a project to be opened for other beneficial public uses.

Jurisdictional Review

The Commission’s jurisdictional review program entails evaluating the jurisdictional status of all licensed projects with license expiration dates within 5 years. This review is conducted to determine the status

of a licensed project, to ensure that the project does meet the jurisdictional criteria as outlined by Section

23(b)(1) of the FPA.

Although the review of projects with license expiration dates within 5 years has found that the majority

of projects fall under the mandatory provisions of section 4(g), there have been several cases where projects

did not meet the jurisdictional criteria. In cases with non-mandatory jurisdiction determination, the Commission will inform the project owner of the results of the investigation. The project owner then can elect to apply

for a new license under the voluntary licensing provisions of section 4(e), or simply withdraw from the

Commission’s licensing process.
34

ENERGY PROJECTS

HYDROPOWER SAFETY

Project Inspections

Inspections verify the structural integrity of dams and compliance with engineering, environmental,

and public safety conditions and regulations. They also identify necessary maintenance and remedial modifications. The Commission is responsible for inspecting about 2,600 dams and related water retention structures. It conducts periodic inspections starting from the receipt of an application for a proposed jurisdictional project, throughout the term of a license. The Commission’s five regional offices conduct the inspections.

Inspections during project construction ensure that the constructed project complies with the approved

design. They also ensure that project construction complies with all applicable federal and state environmental regulations and includes appropriate environmental protection measures, such as erosion control

plans and flow monitoring systems. Construction inspections can uncover unexpected conditions (such as

unknown foundation features) and any need for design changes.

When the project begins operation, focus shifts to ensuring safe operation and maintenance of the

dams. Periodic, on-site operation inspections ensure that dams are maintained for long-term structural integrity of the project works and are repaired if necessary. They also ensure that licensees comply with

license provisions. These inspections safeguard the continued operation of projects, as well as downstream

lives, property, and environment.

Special inspections occur when special issues arise. These may involve potential dam safety problems,

unauthorized projects, complaints about the construction or operation of projects, potential environmental

problems, safety concerns, or compliance issues.

The Commission conducts environmental and public use inspections to confirm that licensees comply with the environmental and public use requirements of the license, and to ensure that the licensee

appropriately protects the environmental resources. Commission environmental specialists also periodically review construction activities to ensure that dam safety and maintenance-related construction activities are environmentally responsible. In addition, the Commission makes special environmental inspections

to investigate environmental compliance problems and environmental damage after flooding or earth or

rock slides, and to determine appropriate protective measures.

Engineering and Environmental Analyses

The Commission keeps abreast of technological advances in field and laboratory investigative and

analytical procedures, including innovative designs for proposed remedial modifications. Keeping abreast

of advances in analytical techniques and dam technology is an important prerequisite to analyzing data and

recommending modifications. The Commission requires licensees to use these new techniques. These efforts have typically resulted in cost savings associated with remediation and have sometimes eliminated the

need for dam safety modification work.

To provide guidance to its engineering staff, dam owners, their consultants, and the rest of the dam

safety community, the Commission publishes Engineering Guidelines for the Evaluation of Hydropower

Projects. These guidelines specify the criteria, analytical methods, engineering parameters, and other engineering aspects related to the design, construction, monitoring, and operation of safe dams. The dam safety

community widely requests and relies on these guidelines. The Commission updates and expands the guidelines as necessary to ensure consistency with state-of-the-art technology.

As dams age and undergo various stress conditions, such as floods and earthquakes, the Commission

increases its monitoring and use of instrumentation data to decide whether the condition of the dams and
35

ENERGY PROJECTS

their appurtenant facilities are changing. This procedure is the key to detecting potential problems before

they become serious and deciding whether new remediation is necessary. With monitoring data available,

the Commission will require licensees and their consultants to continually evaluate the condition and performance of their dams.

Safety Reviews

The Commission’s dam safety program must ensure consistently high safety standards at high and significant hazard potential dams to maintain the lowest probability of failure. In addition to its own periodic

visual inspections and evaluations, the Commission requires periodic independent consultant inspections of

dams with high hazard potential. These inspections include a complete engineering assessment and inspection

of the project works, with a detailed review of the project design and a thorough inspection of project structures. For quality control, Commission dam safety experts approve qualifications of independent consultants.

They also thoroughly review all independent consultant inspection reports for validity of the analysis and

conclusions and the need for additional studies or remedial measures.

Emergency Action Plan (EAP) Tests

All of the inspections, evaluations, remediation, and monitoring, however, cannot guarantee that emergencies will not occur. Therefore, a second line of defense to protect life, property, and the environment is the

development, maintenance, and periodic testing of EAPs. These plans specify actions that owners must take,

in coordination with federal, state and local preparedness agencies, in case of flood, earthquake, or project

facility failure. The Commission is recognized as a national leader in EAPs and regularly shares its expertise

with many other federal and state agencies.

Ensuring Safe Projects: Focus on Aging Hydraulic Components

The proper functioning of the hydraulic components of dams is critical to ensuring dam safety. Without

proper functioning of the hydraulic machinery, penstocks, conduits, gates, and spillways, the necessary control of reservoirs can be lost, resulting in dam failure. While the Commission’s role and responsibility regarding dam safety are quite different from those of other agencies such as the Corps of Engineers, the Bureau of

Reclamation, and the Federal Emergency Management Agency (FEMA), all have common technical dam

safety concerns. In addition, the rest of the dam safety community, including dam owners, state dam safety

agencies, and engineering consultants, have expertise and a vested interest in technical dam safety issues. The

Commission is coordinating within the dam safety community to focus attention on hydraulic component

safety problems. The goal is to develop the proper technical approach to assuring the safety and adequacy of

aging hydraulic components of dams. A well-attended workshop on Tainter Gates was developed and held by

the Commission in early FY 2000. Feedback from participants was very positive and workshop follow-up

activities continued through FY 2000. Additional workshops on other important engineering issues, such as

revised Engineering Guidelines, are being planned.

Electronic Filing of Inspection Reports

The Commission is further developing, perfecting, and implementing procedures for electronic submission of all regional office inspection reports, which include digitized photographs. This procedure allows all

parties, public and private, to readily obtain copies of Commission inspection reports through the Internet. An

additional benefit is the ability for Commission engineers, using digital cameras in the field during project

safety-related incidents, to promptly submit photographs of on-site conditions for review by engineering teams

and supervisors in the office. Staff is continually looking for ways to adapt new technological tools to the

workplace in order to better, or more efficiently, do their jobs.
36

ENERGY PROJECTS

Actions Taken to Improve States’ Dam Safety Programs

Congress established the National Dam Safety Program Review Board (NDSPRB) to advise the Director

of FEMA on implementation of the National Dam Safety Program. The Commission’s dam safety expertise

was influential in the Board’s accomplishments in FY 2000. Accomplishments include grant distribution to all

50 States, and dam safety program improvements being made in every state. Also during FY 2000, new

training activities and opportunities were developed which have resulted in dam safety inspections and analysis review improvements by state dam safety staff. At the request of the State of Alaska Dam Safety Officer,

Commission staff planned a training course on the exercising of emergency action plans for state regulated

dam owners and FERC regulated licensees. The State of Alaska requested that the Commission share its

expertise in emergency action planning to help improve the state’s dam safety program. The course is scheduled for FY 2001 and will be held in Anchorage, Alaska.

Seismicity in the Southeast

In FY 2000 the Commission staff reviewed several site-specific seismicity studies and seismic stability

analyses for projects in the Southeastern part of the United States. The impact of earthquakes on the safety and

stability of FERC licensed dams is an area of concern and requires detailed engineering evaluation. Current

studies have focused on earth dams constructed in the 1930’s, sometimes over loose foundation materials, or

constructed with techniques of that era that produced a loose embankment dam susceptible to drastic strength

reductions during seismic shaking. These evaluations indicate significant modifications are required at several

projects.

Three projects in the southeast where detailed engineering evaluations have shown that the embankment

dam structures will perform poorly during the Maximum Credible Earthquake are: P-516, Saluda Dam, P2232, Wateree Dam, and P-199, Santee Cooper. All of these structures have a high hazard potential classification, and if they failed they could cause significant loss of life, property damage, and environmental harm. The

Commission is considering mitigation measures to minimize any potential problem. Project costs are estimated at approximately $8 million for Santee Cooper, and in excess of $200 million for the massive remediation

of Saluda dam.

Several other embankment dams in the southeast are in the early stage of service evaluation, including

Bridgewater, Mountain Island and Tillery. These projects could eventually require a significant level of

remediation.

Seismicity in the Northwest

In FY 2000, engineering consultants to the Commission completed several seismicity studies in the

Northwest. These studies involved assessing the seismic influence a major rupture from the Cascadia Subduction Zone and the Juan de Fuca Plate would have on several high hazard potential projects. For high hazard

potential projects the Commission Engineering Guidelines requires the project to withstand the Maximum

Credible Earthquake (MCE). Study results are enabling Commission staff to establish new or revised MCE

loads in the Pacific Northwest region. Currently several licensees are reviewing the seismic stability of their

projects using the seismic loadings adopted from the above studies. In addition the Commission is requiring

that dam owners have their independent consultants perform site-specific seismic evaluations for some Part 12

Reports and revise stability analyses when loading conditions change significantly or when previous methods

of analysis are no longer acceptable.
37

ENERGY PROJECTS

Expanded Emergency Action Plan Cooperation

The Commission continues to make improvements to its Emergency Action Plan Exercise Design Course.

The FY 2000 improvements focused on incorporating emergency management personnel into the course, and

providing more assistance to State dam safety programs (see EAP discussion under “Actions Taken to Improve States’ Dam Safety Programs”). The primary objective of the course is to help Commission licensees

better prepare for the testing of their emergency action planning process. To achieve the maximum benefit of

exercising the emergency action plan, participation of all key players involved in the plan is needed. Commission staff emphasizes the importance of the emergency management personnel working closely with the dam

owner to complete the emergency action plan test. Understanding each individual’s role and responsibility

during an emergency is vital in providing a coordinated, effective response to a dam safety emergency. In an

effort to provide various key view points and direct involvement, Commission staff encouraged the attendance

of emergency response personnel at the emergency action plan exercise training courses. Staff’s initiative has

increased the number of emergency management personnel attending the course. The presence of emergency

management personnel provides valuable information and insight to dam owners on how the emergency response and recovery system operates. Commission staff continues to search for ways to improve the relationship between dam owners and emergency management personnel to improve any potential response to an

emergency.
38

A work crew uncouples the shaft from an original 1952 turbine runner at the Cabinet Gorge

hydroelectric project. The shaft will be reused with a new turbine runner. The shaft transmits

mechanical power from the turbine runner to the generator.

Photo courtesy Andrew Vickers/Avista Corp.
39

HYDROELECTRIC POWER TABLE

LICENSE FERC FACILITIES PERIOD

EXPIRATION PROJECT INSTALLATION UNDER OF SUBJ.

DATE OWNER NO. STATE COUNTY RIVER (KW) LICENSE (YEARS) FED.

20000228 PACIFICORP 2659 OR HOOD HOOD RIVER 6000 DM PH 20 N

20000229 OCONTO ELECTRIC COOP 1981 WI OCONTO OCONTO RIVER 1690 DM PH 50 Y

20000331 STURGIS CITY OF 2964 MI ST JOSEPH ST JOSEPH RIVER 2720 DM PH 20 N

20000430 GNE, INC. 2634 ME PISCATAQUIS PENOBSCOT 0 RS 20 N

20000430 DENVER CITY & COUNTY OF 2035 CO BOULDER SOUTH BOULDER CREEK 0 RS 50 N

20000531 INDIANA MICHIGAN POWER CO 2651 IN ELKHART ST JOSEPH RIVER 3440 DM PH 20 N

20000531 CENTRAL VERMONT PUB SERV CORP 2731 VT ADDISON OTTER CREEK 3000 DM PH 20 N

20000531 ERIE BOULEVARD HYDROPOWER, L.P 2047 NY SARATOGA SACANDAGA RIVER 30000 DM PH 50 N

20000614 SOUTHERN CALIFORNIA EDISON CO 372 CA TULUARE TULE RIVER 2520 DM PH 22 Y

20000630 KETCHIKAN CITY OF 420 AK KETCHIKAN KETCHIKAN CREEK 4200 DM PH 18 N

20000630 RHINELANDER PAPER CO 2161 WI ONEIDA WISCONSIN RIVER 2120 DM PH 19 Y

20000630 SOUTH CAROLINA ELECTRIC&GAS CO 1895 SC RICHLAND BROAD RIVER 10600 DM PH 20 Y

20000630 CONSOLIDATED WATER POWER CO 2192 WI WOOD WISCONSIN R 6620 DM PH 20 Y

20000630 NORTHERN STATES POWER CO 2567 WI CHIPPEWA CHIPPEWA RIVER 35280 DM PH 20 N

20000630 CENTRAL VERMONT PUB SERV CORP 2737 VT ADDISON OTTER CREEK 2250 DM PH 20 N

20000630 CONSOLIDATED WATER POWER CO 2110 WI PORTAGE WISCONSIN RIVER 3840 DM PH 23 Y

20000731 NORTHBROOK CAROLINA HYDRO L.L.C 2585 NC FORSYTHE YADKIN RIVER 1410 DM PH 20 Y

20000831 GEORGIA-PACIFIC CORP 2660 ME WASHINGTON ST. CROIX RIVER 0 RS 20 N

20000901 WISCONSIN ELECTRIC POWER CO 2670 WI CHIPPEWA CHIPPEWA RIVER 9500 DM PH 20 N

20000929 GEORGIA-PACIFIC CORP 2618 ME WASHINGTON ST. CROIX RIVER 0 RS 20 N

20000930 BANGOR HYDRO-ELECTRIC CO 2721 ME PENOBSCOT PISCATAQUIS RIVER 1875 DM PH 20 Y

20000930 PACIFIC GAS & ELECTRIC CO 2661 CA SHASTA HAT CREEK 20000 DM PH 25 N

20001031 PACIFICORP 696 UT UTAH AMERICAN FORK CREEK 950 DM PH 25 N

20001130 IDAHO POWER CO 2055 ID OWYHEE SNAKE RIVER 82800 DM PH 50 Y

20001231 NEKOOSA PACKAGING CORP 2902 VA AMHERST JAMES RIVER 512 DM PH 20 N

20001231 NORTHERN POWER CORPORATION 2056 MN HENNEPIN MISSISSIPPI RIVER 28400 DM PH 50 Y

20010125 S D WARREN CO 2942 ME CUMBERLAND PRESUMPSCOT RIVER 2400 DM PH 20 N

20010125 S D WARREN CO 2931 ME CUMBERLAND PRESUMPSCOT RIVER 1900 DM PH 21 N

20010125 S D WARREN CO 2932 ME CUMBERLAND PRESUMPSCOT RIVER 800 DM PH 21 N

20010125 S D WARREN CO 2941 ME CUMBERLAND PRESUMPSCOT RIVER 1000 DM PH 21 N

20010125 S D WARREN CO 2897 ME CUMBERLAND PRESUMPSCOT RIVER 1350 DM PH 22 Y

20010131 CONNECTICUT LIGHT & POWER CO 2597 CT LITCHFIELD HOUSATONIC RIVER 9000 DM PH 20 N

20010131 NEKOOSA PACKAGING CORP 2901 VA AMHERST JAMES RIVER 1875 DM PH 20 Y

20010131 LYNDONVILLE VILLAGE OF 3090 VT CALEDONIA PASSUMPSIC RIVER 350 DM PH 20 N

20010131 VIRGINIA ELECTRIC & POWER CO 2009 NC HALIFAX ROANOKE RIVER 278000 DM PH 50 Y

20010131 ERIE BOULEVARD HYDROPOWER, L.P 2060 NY COLTON TOWN OF COLTON 0 RS 50 Y

20010228 ANTRIM COUNTY 3030 MI ANTRIM ELK RIVER 700 DM PH 20 N

20010228 DAIRYLAND POWER COOP 1960 WI RUSK FLAMBEAU RIVER 15000 DM PH 50 Y

20010330 CONSUMERS ENERGY CO 2566 MI IONIA GRAND RIVER 3250 DM PH 20 Y

20010430 PACIFICORP 2071 WA CLARK LEWIS 134000 DM PH 50 Y

20010731 MARQUETTE CITY OF 2589 MI MARQUETTE DEAD RIVER 3900 DM PH 20 Y

20010731 USGEN NEW ENGLAND, INC. 2077 NH GRAFTON CONNECTICUT RIVER 291360 DM PH 50 Y

20010830 BLACK RIVER FALLS CITY OF 3052 WI JACKSON BLACK RIVER 920 DM PH 20 N

20010831 PACIFICORP 2652 MT FLATHEAD SWAN RIVER 4150 DM PH 25 Y

20010831 GREEN MOUNTAIN POWER CORP 2090 VT WASHINGTON WATERBURY RIVER 5520 DM PH 47 Y

20010901 INTERNATIONAL PAPER CO 2631 MA HAMPDEN WESTFIELD RIVER 2690 DM PH 20 Y

20010930 HAMILTON CITY OF 2724 OH BUTLER MIAMI RIVER 1500 DM PH 20 N

20010930 ENTERPRISE MILL, LLC 2935 GA RICHMOND AUGUSTA CANAL 1200 DM PH 20 N

20010930 AQUENERGY SYSTEMS INC 2416 SC GREENWOOD SALUDA RIVER 6200 DM PH 25 Y

20010930 NANTAHALA POWER & LIGHT CO 2694 NC MACON QUEENS CREEK 1440 DM PH 25 N

20011001 PACIFICORP 472 ID FRANKLIN BEAR RIVER 30000 DM PH 20 Y

20011001 CONNECTICUT LIGHT & POWER CO 2576 CT FAIRFIELD HOUSATONIC RIVER 105900 DM PH 20 N

20011001 PACIFICORP 20 ID CARIBOU BEAR RIVER 14000 DM PH 23 Y

20011001 PACIFICORP 2401 ID CARIBOU BEAR RIVER 40500 DM PH 25 Y

20011031 WISCONSIN ELECTRIC POWER CO 2131 MI DICKINSON MENOMINEE RIVER 7200 DM PH 22 Y

(PROJECTS FOR WHICH LICENSES WILL EXPIRE BETWEEN JANUARY 1, 2000, AND DECEMBER 31, 2006)
40

HYDROELECTRIC POWER TABLE

20011031 WISCONSIN ELECTRIC POWER CO 2073 MI IRON MICHIGAMME RIVER 9600 DM PH 50 Y

20011031 WISCONSIN ELECTRIC POWER CO 2074 MI IRON MICHIGAMME RIVER 2800 DM PH 50 Y

20011130 METROPANITAN RECLAMATION 2866 IL WILL CHICAGO SANITARY 13500 DM PH 20 Y

20011130 NORTH CENTRAL POWER CO INC 2064 WI SAWYER CHIPPEWA RIVER 600 DM PH 50 Y

20011231 WISCONSIN ELECTRIC POWER CO 1759 MI IRON MICHIGAMME RIVER 19944 DM PH 27 Y

20011231 CENTRAL MAINE POWER CO 2142 ME SOMERSET KENNEBEC RIVER 76400 DM PH 47 Y

20011231 TACOMA CITY OF 2016 WA LEWIS COWLITZ RIVER 460000 DM PH 50 Y

20011231 PORTLAND GENERAL ELECTRIC CO 2030 OR JEFFERSON DESCHUTES RIVER 416100 DM PH 50 Y

20011231 WISCONSIN ELECTRIC POWER CO 2072 MI IRON PAINT RIVER 100 DM PH 50 Y

20020131 PUD NO 1 OF PEND OREILLE CNTY 2042 WA PEND OREILLE PEND OREILLE 60000 DM PH 50 N

20020131 ERIE BOULEVARD HYDROPOWER L.P. 2084 NY ST LAWRENCE RAQUETTE RIVER 101250 DM PH 50 Y

20020223 EL DORADO IRRIGATION DISTRICT 184 CA EL DORADO SOUTH FORK AMERICAN 20000 DM PH 22 Y

20020331 FORT JAMES OPERATING COMPANY 2312 ME PENOBSCOT PENOBSCOT RIVER 7655 DM PH 39 Y

20020731 COMINCO AMERICAN INC 2103 WA PEND O’REILLE CEDAR CREEK 0 RS 50 N

20020903 SPRINGVILLE CITY OF 2031 UT UTAH BARTHOLOMEW CR 2000 DM PH 50 N

20020930 HART CITY OF 3516 MI OCEANA PENTWATER RIVER 352 DM PH 20 N

20021012 SITHE PENNSYLVANIA HOLDINGS 309 PA CLARION CLARION RIVER 28800 DM PH 23 Y

20021031 HYDRO DEVELOPMENT GROUP INC 6059 NY ST LAWRENCE OSWEGATCHIE RIVER 900 DM PH 20 N

20021101 TRINITY CONSERVANCY INC 719 WA CHELAN PHELPS CREEK 240 DM PH 23 N

20021201 NEW YORK STATE ELEC & GAS CORP 2835 NY CLINTON AUSABLE RIVER 2640 DM PH 20 Y

20021231 HYDRO DEVELOPMENT GROUP INC 6058 NY ST LAWRENCE OSWEGATCHIE RIVER 1490 DM PH 20 N

20030131 WOODS LAKE HYDRO CO 3410 CO EAGLE LIME CREEK 45 DM PH 20 N

20030228 NEW YORK STATE ELEC & GAS CORP 2852 NY STEUBEN MUD CREEK 2000 DM PH 20 Y

20030228 ENTERGY, ARKANSAS, INC. 271 AR HOT SPRINGS OUACHITA 65300 DM PH 23 Y

20030331 AVONDALE MILLS INC 5044 GA RICHMOND AUGUSTA CANAL 2475 DM PH 20 N

20030426 SOUTHERN CALIFORNIA EDISON CO 344 CA BERNARDINO SAN GORGONIO RIVER 2250 DM PH 20 Y

20030430 PAROWAN CITY CORP 2782 UT IRON RED CREEK 500 DM PH 25 N

20030606 FORD MOTOR CO 362 MN RAMSEY MISSISSIPPI RIVER 17920 DM PH 23 Y

20030630 PCA HYDRO INC 2180 WI LINCOLN WISCONSIN RIVER 3000 DM PH 26 Y

20030731 BURFORD JUDITH A 6418 CO EAGLE EAST BRUSH CREEK 11 DM PH 20 N

20030824 MINNESOTA POWER & LIGHT CO 346 MN MORRISON MISSISSIPPI RIVER 18000 DM PH 23 Y

20030831 SOUTHERN CALIFORNIA EDISON CO 2086 CA FRESNO MONO CREEK 0 RS 50 N

20030918 INDIANA MICHIGAN POWER CO 401 MI ST. JOSEPH ST JOSEPH RIVER 1750 DM PH 25 Y

20030930 CHAR TER TOWNSHIP OF YPSILANTI 5334 MI WASHTENAW HURON RIVER 3413 DM PH 20 N

20030930 PACIFIC GAS & ELECTRIC CO 2107 CA BUTTE FEATHER RIVER 142830 DM PH 50 N

20031031 PACIFIC GAS & ELECTRIC CO 233 CA SHASTA PIT RIVER 317000 DM PH 22 Y

20031031 MINNESOTA POWER & LIGHT CO 469 MN LAKE KAWISHIWI 4000 DM PH 22 Y

20031031 NEW YORK POWER AUTHORITY 2000 NY ST LAWRENCE ST LAWRENCE RIVER 912000 DM PH 50 N

20031231 POTOMAC EDISON CO 2516 W V BERKELY POTOMAC RIVER 1900 DM PH 27 N

20031231 POTOMAC EDISON CO 2517 W V BERKELY POTOMAC RIVER 1210 DM PH 27 N

20040131 NEWTON FALLS INC. 7000 NY ST LAWRENCE OSWEGATCHIE RIVER 2220 DM PH 20 Y

20040331 S D WARREN CO 2984 ME CUMBERLAND PRESUMPSCOT 1800 DM PH 20 Y

20040331 PUD NO 1 OF CHELAN COUNTY 637 WA CHELAN CHELAN RIVER 48000 DM PH 30 Y

20040410 MIDWEST HYDRO, INC 287 IL LASALLE FOX RIVER 3680 DM PH 24 Y

20040430 MADISON PAPER INDUSTRIES 2364 ME SOMERSET KENNEBEC RIVER 16977 DM PH 40 Y

20040430 MADISON PAPER INDUSTRIES 2365 ME SOMERSET KENNEBEC RIVER 9000 DM PH 40 Y

20040430 MERIMIL LTD PARTNERSHIP 2574 ME KENNEBEC KENNEBEC RIVER 6770 DM PH 40 Y

20040430 UNITED WATER CONSERVATION DIST 2153 CA VENTURA PIRU CREEK 1420 DM PH 50 Y

20040630 WISCONSIN PUBLIC SERVICE CORP 1979 WI LINCOLN WISCONSIN RIVER 4200 DM PH 30 Y

20040731 NORWAY CITY OF 2720 MI DICKINSON MENOMINEE RIVER 5636 DM PH 20 Y

20040731 IDAHO POWER CO 2726 ID GOODING BIG WOOD RIVER 21770 DM PH 25 Y

20040930 BARTON VILLAGE INC 7725 VT ORLEANS CLYDE RIVER 1300 DM PH 20 N

20040930 PPL HOLTWOOD, LLC 487 PA WAYNE LACKAWAXEN RIVER 40000 DM PH 30 Y

20041031 BUFFALO HYDRO L.C. 1413 ID FREMONT BUFFALO RIVER 250 DM PH 25 N

20041031 PACIFIC GAS & ELECTRIC CO 2105 CA PLUMAS FEATHER RIVER 342628 DM PH 50 Y

LICENSE FERC FACILITIES PERIOD

EXPIRATION PROJECT INSTALLATION UNDER OF SUBJ.

DATE OWNER NO. STATE COUNTY RIVER (KW) LICENSE (YEARS) FED.
41

HYDROELECTRIC POWER TABLE

20041112 PETERSBURG CITY OF 201 AK WRANGELL CRYSTAL CREEK 2000 DM PH 30 Y

20041116 PORTLAND GENERAL ELECTRIC CO 477 OR CLACKAMAS SANDY RIVER 21000 DM PH 25 Y

20041130 INTERNATIONAL PAPER CO 4914 WI BROWN FOX RIVER 1078 DM PH 20 N

20041230 PAROWAN CITY CORP 1273 UT IRON CENTER CREEK 600 DM PH 30 N

20041231 MOSINEE PAPER CORP 2207 WI MARATHON WISCONSIN RIVER 3050 DM PH 30 Y

20041231 MONTANA POWER CO 2543 MT MISSOULA CLARK FORK 3200 DM PH 40 Y

20041231 OAKDALE & SAN JOAQUIN IRR DIST 2005 CA TUOLUMNE STANISLAUS R 63990 DM PH 50 Y

20041231 OAKDALE & SAN JOAQUIN IRR DIST 2067 CA TUOLUMNE STANISLAUS RIVER 17100 DM PH 50 Y

20041231 PACIFIC GAS & ELECTRIC CO 2130 CA TUOLUMNE STANISLAUS 87900 DM PH 50 Y

20041231 GEORGIA POWER CO 2177 GA HARRIS CHATTAHOOCHEE RIVER 115600 DM PH 50 Y

20041231 PORTLAND GENERAL ELECTRIC CO 2233 OR CLACKAMAS WILLAMETTE R 16800 DM PH 50 Y

20050228 SOUTHERN CALIF EDISON CO 382 CA KERN KERN R 12,000 DM PH 25 Y

20050228 TAPOCO INC 2169 TN MONROE LITTLE TENNESSEE R 326,500 DM PH 50 Y

20050331 WISCONSIN ELECTRIC POWER 2697 WI DUNN RED CEDAR R 6,000 DM PH 25 Y

20050331 SOUTHERN CALIF EDISON CO 2174 CA FRESNO RANCHERIA CR,BIG CR 10,800 DM PH 50 Y

20050331 WISCONSIN ELECTRIC POWER 2181 WI DUNN RED CEDAR R 5,400 DM PH 50 Y

20050430 PACIFIC GAS & ELECTRIC CO 178 CA KERN KERN R 11,500 DM PH 25 Y

20050430 ALABAMA ELECTRIC COOP INC 2586 AL CRENSHAW CONECUH R 8,250 DM PH 25 N

20050531 MARSHALL, CITY OF 6514 MI CALHOUN KALAMAZOO R 319 DM PH 20 N

20050531 GRAND RIVER DAM AUTH 2183 OK MAYES NEOSHO R 100,000 DM PH 50 Y

20050630 N. E. W. HYDRO INC ET AL 7264 WI OUTAGAMIE FOX R 1,390 DM PH 20 Y

20050630 PACIFICORP 2630 OR JACKSON N FK ROGUE R 36,760 DM PH 25 Y

20050630 FPL ENERGY MAINE HYDRO LLC 2194 ME YORK SACO R 4,000 DM PH 50 Y

20050730 NANTAHALA PWR AND LT CO 2601 NC SWAIN OCONALUFTEE R 980 DM PH 25 Y

20050730 NANTAHALA PWR AND LT CO 2602 NC JACKSON TUCKASEGEE R 225 DM PH 25 Y

20050730 NANTAHALA PWR AND LT CO 2603 NC MACON LITTLE TENNESSEE R 1,040 DM PH 25 Y

20050731 NANTAHALA PWR AND LT CO 2619 NC CLAY HIWASSEE R 1,800 DM PH 25 Y

20050731 IDAHO POWER CO 1971 OR BAKER SNAKE R 1,166,500 DM PH 50 Y

20060131 NANTAHALA PWR AND LT CO 2698 NC JACKSON TUCKASEGEE RIVER 26,175 DM PH 25 N

20060131 NANTAHALA PWR AND LT CO 2686 NC JACKSON TUCKASEGEE RIVER 24,600 DM PH 25 N

20060214 MONROE CITY CORPORATION 632 UT SEVIER MONROE CREEK 250 DM PH 28 N

20060228 PACIFICORP 2082 CA SISKIYOU KLAMATH RIVER 151000 DM PH 52 N

20060228 NANTAHALA PWR AND LT CO 2692 NC CLAY NANTAHALA RIVER 43200 DM PH 25 N

20060228 UNION ELECTRIC CO 459 MO BENTON OSAGE 176200 DM PH 25 Y

20060331 SOUTH CAROLINA PUBLIC AUTHORITY 199 SC BERKELEY SANTEE RIVER 134520 DM PH 27 N

20060412 N Y ST ELEC & GAS CORP 2738 NY CLINTON SARANAC RIVER 38950 DM PH 26 N

20060430 PUGET SOUND PWR AND LT CO 2150 WA SKAGIT BAKER RIVER 162400 DM PH 50 N

20060430 PACIFICORP 2111 WA CLARK LEWIS RIVER 240000 DM PH 50 N

20060430 COWLITZ CO PUD NO 1 2213 WA COWLITZ LEWIS RIVER 70000 DM PH 50 N

20060430 PACIFICORP 935 WA CLARK LEWIS RIVER 135000 DM PH 23 N

20060630 CHELAN CO PUD 1 2145 WA DOUGLAS COLUMBIA R 1236600 DM PH 50 N

20060831 PORTLAND GENERAL ELEC CO 2195 OR CLACKAMAS CLACKAMAS RIVER 91900 DM PH 50 N

20060831 PORTLAND GENERAL ELEC CO 135 OR CLACKAMAS OAK GROVE FORK 40825 DM PH 26 Y

20061130 ERIE BOULEVARD HYDROPOWER, L.P. 7321 NY FRANKLIN SALMON RIVER 1000 DM PH 20 N

20061231 CITY & COUNTY OF DENVER 2204 CO GRAND WILLIAMS FORK RIVER 3000 DM PH 43 N

20061231 MONTANA POWER CO 2543 MT MISSOULA CLARK FORK 3200 DM PH 38 N

*INCLUDES TYPES OF FACILITIES AT EACH PROJECT, BUT NOT TOTAL NUMBER OF EACH TYPE (E.G. A PROJECT MAY CONSIST OF MULTIPLE POWERHOUSES

OR DAMS). DM DAM, RS RESERVOIR,CL CANAL, TU TUNNEL, FM FLUME, PI PIPELINE, PK PENSTOCK, PH POWERHOUSE, TR TURBINE, GN GENERATOR(S), TC

TAILRACE, TL TRANSMISSION LINE OR CONNECTION THERETO.

LICENSE FERC FACILITIES PERIOD

EXPIRATION PROJECT INSTALLATION UNDER OF SUBJ.

DATE OWNER NO. STATE COUNTY RIVER (KW) LICENSE (YEARS) FED.
42

For Additional Information Contact:

Federal Energy Regulatory Commission

Office of External Affairs

888 First Street, NE

Washington, DC 20426

202/208-0004

Printed 2001
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